More annual reports from National Fuel Gas Company:
2023 ReportPeers and competitors of National Fuel Gas Company:
Southwest Gas Holdings IncNational Fuel Gas Company 2 0 0 0 A n n u a l R e p o r t A N D F O R M 1 0 - K Buying and Building Real Assets for the Future Corporate Profile National Fuel Gas Company, incorporated in 1902, is a diversified energy company with its headquarters in Buffalo, New York. The Company’s $3.2 billion in assets is distributed among six business segments: Exploration and Production, Utility, Pipeline and Storage, Basic Earnings Per Common Share Dollars Per Common Share 2.91(1) 3.01 2.98 3.25 Timber, International and Energy Marketing. 2.78 National Fuel’s history dates to the earliest dates of the natural gas and oil industry in the United States, and the Company has been .61 responsible for many industry firsts. Today, the Company continues to be managed in the same innovative and entrepreneurial spirit. Exploration and Production Seneca Resources Corporation explores for, develops and purchases natural gas and oil reserves in the Gulf Coast Region of Texas and Louisiana, the Appalachian Region, the Rocky Mountain Region, California and the western provinces of Canada. Currently, Seneca’s exploration emphasis is cen- tered around the Gulf Coast in offshore waters and new reserves in Canada, while development drilling continues to expand in California. Utility National Fuel Gas Distribution Corporation sells or transports natural gas to over 735,000 customers through a local distribution system located in western New York and northwestern Pennsylvania. The major areas served by this system include Buffalo, Niagara Falls and Jamestown in New York, and Erie and Sharon in Pennsylvania. Pipeline and Storage National Fuel Gas Supply Corporation provides interstate natural gas trans- portation and storage for affiliated and nonaffiliated companies through an integrated gas pipeline system that extends 3,065 miles from southwestern Pennsylvania to the New York-Canadian border at the Niagara River. It also owns 29 underground natural gas storage areas and is co-owner and operator of four others. Timber Highland Forest Resources, Inc. and Seneca Resources Corporation, Northeast Division carry out the Timber segment operations for the Company. Highland operates four sawmills in northwestern Pennsylvania. Seneca markets timber from its New York and Pennsylvania land holdings. International Horizon Energy Development, Inc. engages in foreign energy projects through the investments of its indirect subsidiaries as the sole or substantial owner of various business entities. In addition to assets in the Czech Republic, Horizon continues to evaluate prospects throughout eastern and central Europe. Energy Marketing National Fuel Resources, Inc. is engaged in the marketing and brokerage of natural gas and electricity and the performance of energy management serv- ices for industrial, commercial, public authority and residential end-users throughout the northeast United States. COVER: Buying and building real assets for the future include investments made in drilling, technology and capacity expansion by the Exploration and Production, Utility, and Pipeline and Storage segments of National Fuel Gas Company. 1996 1997 1998 1999 2000 (1) Excludes special items for impairment of oil and gas producing assets and for cumulative effect of change in accounting. Expenditures for Long-Lived Assets by Segment 1%3% 3% 14% 9% 70% Total: $398.8 million Net Plant by Segment 4% 6% 37% 35% 18% Total: $2.7 billion Utility Pipeline and Storage Exploration and Production International Timber All Other and Corporate Note: All references to years in this Annual Report are to the Company’s fiscal year, which ends September 30. All references to earnings per share are for basic earnings per common share. IN 2OOO: · Net income of $34.9 million con- tributed 27% of total Company earnings. · Record production of 72.6 Bcf equivalent from 119 successful wells with a 91% success rate. · Acquisition in Canada contributed approximately 233 Bcf equivalent to total reserve base. · Total reserves increased 31% to 1.02 Trillion cubic feet equivalent. Exploration and Production Pipeline and Storage OUTLOOK:* 30% to 95-100 Bcf equivalent. · Increase total production by over · Capital budget of $165 million · Over 250 wells planned for 2001. · Emphasis on exploitation of oil planned, excluding acquisitions. and gas reserves. At a Glance Timber IN 2OOO: · Net income of $31.6 million was nearly 25% of total Company earnings. · Received Federal Energy Regulatory Commission (FERC) certification in July 2000 for Independence Pipeline project. OUTLOOK:* · Focus our expansion plans to increase transportation capacity into Leidy Hub. · Also focus on developing incre- mental expansion of pipelines near Canadian border to further benefit from our location between Canada and East Coast markets. IN 2OOO: · Net income increased nearly 29% to $6.1 million, or 5% of total Company earnings. · Produced 24.6 million board feet, an increase of 16% from fiscal 1999 production. OUTLOOK:* · Increase logging operations to · Monetize timber assets through nearly 28.0 million board feet. increased cutting and selling non-core properties. IN 2OOO: · Net income of $57.7 million contributed over 45% of total Company earnings. · A new three-year rate plan became effective October 1, 2000 in New York. Provides for rate reductions for customers and a target level of 11.5% return on equity. · Monitoring reliability and cost efficiency of additional electric power provided by gas-powered microturbines. Utility OUTLOOK:* · Pursue market for new sites of natural gas-fired electric generation for industrial applications. · Promote “value added” services and products to meet needs of our entire utility customer base. · Continue to work with regulatory commissions in New York and Pennsylvania on defining industry restructuring. · Maintain emphasis on strengths: superior customer service, cost containment with technology efficiencies, and continued transi- tion to competition. Energy Marketing International IN 2OOO: · Net loss of $7.8 million incurred from marking-to-market derivative financial instruments and accruing a loss contingency for unhedged fixed price sales contracts. · Doubled number of residential gas customers from 13,300 to 27,185. OUTLOOK:* · Focus on historical strength of providing quality service and savings to customers. · Continue to pursue opportunities from electric and gas industry restructuring. IN 2OOO: · Net income of $3.3 million was · Completed merger of SCT and 43% higher than 1999 earnings. PSZT to form new company, United Energy, a.s. OUTLOOK:* · Focus on competing for opportu- nities in the newly restructuring electric market in Europe. · Continue to evaluate additional prospects throughout eastern and central Europe. CONTENTS 2 Highlights 3 Letter to Shareholders 17 Form 10-K 94 Officers 95 Directors 96 Glossary 97 Investor Information 1 Highlights Year Ended September 30 Operating Revenues (Thousands) Net Income Available for Common Stock (Thousands) Net Income Available for Common Stock Before Special Items (Thousands) Return on Average Common Equity Return on Average Common Equity Before Special Items Per Common Share Basic Earnings Diluted Earnings Basic Earnings Before Special Items Diluted Earnings Before Special Items Dividends Paid Dividend Rate at Year-End Book Value at Year-End Common Shares Outstanding at Year-End Weighted Average Common Shares Outstanding Basic Diluted Average Common Shares Traded Daily Common Stock Price High Low Close 2000 1999 1998 1997 1996 $1,425,277 $ 127,207 $1,263,274 $ 115,037 $1,248,000 23,188 $ $1,265,812 $ 114,688 $1,208,017 $ 104,671 $ 127,207 13.2% $ 115,037 12.6% $ 111,418(1) 2.6% $ 114,688 13.0% $ 104,671 12.6% 13.2% 12.6% 11.9%(1) 13.0% 12.6% $ 3.25 $ 3.21 $ 3.25 $ 3.21 $ 1.88 $ 1.92 $25.11 39,329,803 39,116,921 39,583,100 79,271 $58.81 $39.38 $56.06 $ 2.98 $ 2.95 $ 2.98 $ 2.95 $ 1.82 $ 1.86 $24.19 38,837,499 38,663,981 39,041,728 60,663 $50.00 $37.50 $47.19 $ 0.61 $ 0.60 $ 2.91(1) $ 2.88(1) $ 1.76 $ 1.80 $23.14 38,468,795 $ 3.01 $ 2.98 $ 3.01 $ 2.98 $ 1.70 $ 1.74 $23.94 38,165,888 38,316,397 38,703,526 62,741 38,083,514 38,440,018 59,456 $49.13 $39.63 $47.00 $45.44 $36.63 $44.00 $ 2.78 $ 2.77 $ 2.78 $ 2.77 $ 1.64 $ 1.68 $22.61 37,851,655 37,613,305 37,825,453 50,143 $38.00 $28.50 $36.75 Net Cash Provided by Operating Activities (Thousands) Total Assets (Thousands) Expenditures for Long-Lived Assets (Thousands) $ 238,246 $3,236,888 $ 398,777 $ 267,504 $2,842,586 $ 265,527 $ 249,863 $2,684,459 $ 507,537 $ 294,662 $2,267,331 $ 248,311 $ 168,469 $2,149,772 $ 174,502 Volume Information Utility Throughput-MMcf Gas Sales Gas Transportation Pipeline & Storage Throughput-MMcf Gas Transportation Production Volumes Gas-MMcf Oil-Mbbl Total-MMcfe Proved Reserves Gas-MMcf Oil-Mbbl Total-MMcfe Energy Marketing Volumes-MMcf Gas International Sales Volumes Heating (Gigajoules) Electricity (Megawatt hours) Average Number of Utility Retail Customers Average Number of Utility Transportation Customers Number of Employees at September 30 97,617 71,862 101,675 64,086 108,599 60,080 127,501 57,310 132,742 57,212 313,548 308,303 313,048 300,302 325,006 41,670 5,147 72,552 301,667 119,697 1,019,849 37,166 4,016 61,262 320,792 75,819 775,706 36,474 2,614 52,161 325,065 66,591 724,611 38,586 1,902 49,998 232,449 17,981 340,335 38,767 1,742 49,219 207,082 25,749 361,576 35,465 34,454 26,453 21,024 20,232 10,222,024 1,147,303 10,047,042 1,138,980 7,116,776 763,848 658,696 693,023 704,217 78,610 3,597(2) 41,515 3,807(2) 28,224 3,944(2) 262,615 — 731,034 2,013 2,524 36,652 — 732,493 1,733 2,843 (1)Excludes oil and gas asset impairment of ($79.1) million or ($2.06) per common share (basic) and ($2.04) per common share (diluted) and Cumulative Effect of Change in Accounting of ($9.1) million or ($0.24) per common share (basic and diluted). (2) Includes 1,201, 1,406 and 1,390 international employees at September 30, 2000, 1999 and 1998, respectively. 2 The year 2000 has meant many things to many people. A year ago, investors were being lured by the flash-and-spin of fledgling dot-com ventures, but in 2000 many of them discovered that the potential consequences of putting their savings into compa- nies with no track record and no real assets were more than theoretical. In fiscal 2000, National Fuel’s shareholders, by contrast, enjoyed record earnings of $3.25 per share, record dividends of $1.92 per share, stock price appreciation of nearly 19%, ownership of real and substantial assets, and a track record that is nearly a century long. This year was particularly gratifying to the management of your Company because it vindicated the wisdom of a very long-term strategy that many other gas companies previously pursued but eventually abandoned - prematurely, we would argue. The Arab oil embargoes of the ’70’s triggered a series of events - rising gas prices, inflation, and high interest rates - that created a very difficult environment for gas utilities. Then, the conservation response to higher prices eroded our sales, inflation and high interest rates increased our expenses, and the consequent hostility to utility rate increases impaired our profitability. At the same time oil and gas producers were enjoying such prosperity that a new term and a new tax were invented - windfall profits. We determined then that we would not be bystanders the next time such an occasion arose. Indeed, today we are meaningful beneficiaries of rising oil To Our Shareholders: and gas prices, as detailed in our segment on exploration and production. The fact that we, through our activity in the Exploration and Production segment, are benefiting from rising oil and gas commodity prices is not some random windfall or some lucky break. Rather, it is the result of careful planning and strategic positioning. You, our shareholders, paid the “insurance premiums” in fiscal 1995 when prices fell and our earnings dropped to $2.03 per share and in fiscal 1998 when prices dropped and we wrote down the value of our oil and gas reserves by $79.1 million after tax. In those years gas consumers, who are under- standably upset with paying high gas prices today, realized lower bills as a result of lower commodity prices. Whatever wisdom we can claim in positioning your Company to be prepared for rising prices came from years of experience, not from instants of insight. While changes in the industry have generally benefited the Company, individual segments are affected in different ways at different times. However, by building a strong portfolio of investments, keeping operations trim and efficient, and aggressively pursuing sound opportunities, we expect to continue providing consistent, healthy returns for our shareholders.* Bernard J. Kennedy (right), Chairman of the Board and Chief Executive Officer with Philip C. Ackerman, President 3 Following the acquisition of Tri Link Far left: This solution gas processing Resources, Ltd., now National Fuel facility near the Hazelwood Pool, sep- Exploration Corp. (NFE), an oil and arates oil, natural gas and propane, gas exploration and production firm which are then stored in tanks or with operations in the Canadian shipped out by pipeline. provinces of Alberta, Manitoba and Left: Well-pulling operations on a Saskatchewan, development drilling Tilston Pool well are used to remove has focused in several locations in and repair tubing for maximum Saskatchewan. Above: An oil well pumping unit NFE operates in its Red River Pool. production from NFE holdings in this area. Fifty-five development wells in the Tilston Pool are scheduled for production during fiscal 2001.* 4 Annual Dividend Rate at Year End Dollars Per Common Share 1.92 We plan to continue to build that portfolio of energy-related assets, especially expanding our investment in exploration and production to take advantage of the current high prices.* We are mindful, however, that most of our shareholders and all of our creditors are uneasy with any significant increase in our risk profile. Accordingly, we have placed an emphasis on low risk drilling and acquiring proved reserves, which, 1.42 combined with our price hedging program, substantially reduces the risk of exploration 1990 1992 1994 1996 1998 2000 not in one basket, but exploration and production has grown to 37% of National and production.* A balanced, integrated company is less risky than a pure utility as all our eggs are Return on Average Common Equity 12.6 13.0 Percent 11.9(1) 12.6 13.2 2.6 1996 1997 1998 1999 2000 (1) Excludes special items for impairment of oil and gas producing assets and for cumulative effect of change in accounting. Fuel’s net plant, and its prospects for future growth are tremendous. We want to main- tain National Fuel’s balance, so we are examining various ways either to expand our regulated component or to reduce our exploration and production exposure.* This past June your Board of Directors increased the annual dividend for the 30th consecutive year, from $1.86 per share to $1.92 per share. National Fuel has paid divi- dends without interruption since its establishment in 1902 - proof, once again, that our assets are real and substantial - and our longevity and dividend history is rivaled by few publicly traded companies. There is more good news to look forward to during the coming fiscal year. We announced in late October that we expect earnings for fiscal 2001 to be in the range of $4.25 to $4.35 per share.* Increased earnings from favorable commodity pricing and an expected increase of over 30% in total oil and gas production should more than offset the earnings impact from our recent New York utility rate settlement.* Building a solid company in the energy business is not like building a sandcastle, which may be both captivating and trendy, but is durable just until the next incoming tide. Only by building brick by brick, or segment by segment, can we achieve a bal- anced structure designed and tested to withstand the shifting tides of the economy, weather, ecological demand, and alternating regulatory philosophies. We think we’ve AB SK MB CANADA done that. Let’s take a brief look at those building blocks. WY USA CA MI NY PA TX LA Seneca Resources Exploration and Production Record production of 72.6 Bcf equivalent, net income of $34.9 million, or $.89 per share, and a major acquisition were the fiscal 2000 highlights for our Exploration and Production segment. With the June acquisition of Tri Link Resources, Ltd. (Tri Link) in Canada, Seneca Resources Corporation (Seneca) acquired a major growth opportu- nity in Canada. Headquartered in Calgary, Alberta, Tri Link - now called National Fuel Exploration Corp. (NFE) - operates wells in Alberta, Saskatchewan, and Manitoba. This acquisition immediately added some 38.9 million barrels of oil to National Fuel’s assets. Our return on that investment was immediately gratifying. In the remaining three and one-half months of fiscal 2000, NFE contributed revenues of $28.4 million and earnings of $6.4 million or $.16 per share. 5 The completion phase of the well at Eugene Island Block 271/264 is shown below. Initial production began in August 2000, and the well is producing natural gas at a daily rate of 10 million cubic feet. Further, the new venture provides us with a critical entrée to the relatively untapped oil and gas frontier north of the border. It could take 10-20 years to fully exploit NFE’s extensive oil reserves.* Our geologists have identified as many as 150 potential new development drilling locations. Oil is only half of the equation, for Canada has great potential as a source for pro- viding substantial quantities of the natural gas that is needed to fulfill the long-term natural gas requirements for the United States. This acquisition helps assure our partici- pation in this future growth.* Using NFE as a base of operation, our evaluation team is ideally situated to scout for other promising drilling sites in Canada and to move quickly if the Company should decide to acquire them. Here in the United States, our recent purchase of more steam generating equip- ment has positioned us to begin a faster, more efficient method of steam flooding in our oil wells in the North Lost Hills area of California. This process is used to thin the viscous oil for easier extraction. The industry’s traditional, time-consuming “huff-and- puff” method requires steam to be injected into a single well continuously for two weeks. The well then “soaks” for another two weeks before pumping can begin, and the process must be repeated after a few months. Using our new steam generator, we plan to introduce steam continuously into a central well from which it is forced into four adjacent wells.* The ongoing flow of steam in this five-spot procedure enables production to continue without interruption.* We now have four five-spot steam-flooding operations in place in North Lost Hills. We expect that the impact of the steam floods in that area will result in increased production beginning in our second quarter of fiscal 2001.* Four confirmation wells drilled in the Tulare zone in our Midway-Sunset field in the San Joaquin Basin verified another potential new source of production. We have already begun mapping the zone and laying plans for a drilling program in that area. Although the costs of rig leasing for offshore drilling have risen dramatically in recent months, the corresponding high prices of oil and gas make it economically advantageous for Seneca to continue our drilling projects on the Gulf Coast.* Our ability to pinpoint new reserves is enhanced by the use of 3-D seismic imaging of the productive formations. Recent refinements in computer technology have made it possi- ble to increase our accuracy in identifying the most profitable sites for drilling. The pipes in the foreground carry (at separate times) both steam to and production from wells at Seneca’s Midway-Sunset field in California. These cyclic steaming operations heat the oil reserves, which increases each well’s oil producing capability. Oil and Gas Production In Bcf Equivalent 72.6 61.3 49.2 50.0 52.2 Oil and Gas Prices Weighted Average After Hedging Dollars 22.85 18.01 17.95 13.03 12.96 2.11 2.18 2.27 2.24 2.61 Proved Developed and Undeveloped Reserves In Bcf Equivalent 1,019.9 724.6 775.7 361.6 340.3 1996 1997 1998 1999 2000 1996 1997 1998 1999 2000 1996 1997 1998 1999 2000 Oil Gas 6 Oil (per bbl) Gas (per Mcf) Oil Gas In fiscal 2001 we have started a 44-well drilling program in our Appalachian hold- ings near St. Mary’s in northwest Pennsylvania.* This program is the culmination of a three-year effort in researching and developing these prospects. It is relatively inexpen- sive to drill wells in this region where we estimate average daily production rates from these new wells will reach 2-4 million cubic feet per day.* Our exploration and production capital budget of $165 million anticipates drilling nearly 250 wells: Canadian activities will require approximately $60 million; our California development program has $25 million allocated; roughly $6 million will be spent on our Appalachian drilling program; and $74 million is planned for Gulf Coast operations.* Utility The Utility segment of National Fuel remains the bedrock of our Company, con- tributing the largest portion of overall net income. Specifically, this segment provided earnings this year of $57.7 million, or $1.47 per share. We are just beginning, however, to enter a time of turmoil for gas and electric consumers as the market comes to grips with supply and demand imbalances in a structure where some old forms of regulation have been abandoned. So far, this has meant soaring prices for electricity in California with the threat of brownouts or even blackouts, and for natural gas users, nationwide, unprecedented commodity prices this year long before the onset of the winter season. The combination of this pricing environment and the expected continued effort to develop a reasonable and practical model for customer choice promise to make the coming year one of our most challenging.* Locally in western New York, we have had the unfortunate experience of seeing consumers suffer the consequences of expecting relatively small marketers to have the same resources as billion-dollar utilities. It is true that we feel we serve our customers best when they need not think of us at all. However, customer choice programs have led our customers to think long and hard about the services we provide as compared to those offered by energy marketers. We have embraced “unbundling” or “restructuring” or, more simply, “transporta- tion” for over 15 years and in that time our larger volume customers have realized sub- stantial savings. Now, as prices rise and the gas market becomes more difficult to deal with, state and federal policy makers must decide whether they truly wish all con- sumers to obtain their gas and electricity in a competitive market where the operative expression is “Let the buyer beware.” Regardless of its structure, the outlook for the gas industry as a whole has never been brighter.* We should not lose sight of the fact that these high prices, while a diffi- culty for consumers, are resulting from increases in demand. This demand for natural Lake Ontario NY CANADA Buffalo Lake Erie Erie PA Distribution Corporation Service Area National Fuel Director Bernard S. Lee, PhD, explains the operation of the fuel processor and the fuel cell stack in this cut-away model of a residential fuel cell to a group of employees at the Company’s Annual Management Conference. These devices provide low- cost power due to their high electrical efficiency and also operate without combustion, making them extremely attractive from an environmental perspective. Employees pictured (from left): Diane Banks, David Drebot, Michael Laughlin, John Webb and Dianna McLaughlin. 7 8 Two gas-fired microturbines were installed at Westwood Village to increase the reliability and cost effec- tiveness of the assisted living commu- nity’s energy supply. Pictured (from left): Elderwood Associates Director of Development David Tosetto and Utility employees Robert Eck and James Lalley. gas will only increase if, as expected, coal-fired power plants convert to gas-fired systems.* Environmental requirements, especially in New York, make power plant con- versions to natural gas even more likely.* In addition, the Company is pursuing the market for new sites of natural gas-fired electric generation for industrial applications across its service territory. Clearly, the incremental load opportunity from conversion to and expanded use of gas-fired electric generation for the industrial sector is very attrac- tive. Expanded use of clean-burning, utility-delivered natural gas produces multiple benefits for shareholders, ratepayers, and the environment. We are also focused on the efficiency and practicality of gas-fired microturbines that can be installed in smaller volume industrial plants, commercial establishments, individual homes, or subdivisions to supplement or replace electricity drawn from the grid during times of peak use. As the nation increases its consumption of electricity to run computers, CD players, TV sets, microwave ovens, and other electric appliances, microturbines will likely help alleviate the strain on power plants and prevent interrup- tion of service.* Though economic only in specialized circumstances at the present time, microturbines are expected to drop in price as greater quantities are produced for the open market.* We are testing the reliability and cost efficiency of current models at Westwood Village, an assisted-living facility in West Seneca, New York. Two microturbines provide additional power for the facility during hours of peak use on weekdays, generating both electricity and hot water. Their operation has been evaluated continuously since their installation in June 2000. Once we are convinced of their value and reliability, promoting their use for residential, commer- Sharon Tube recently built this $26.5 million, 84,000 square-foot manufac- turing facility in Wheatland, Pennsylvania. Utility employee John Senger (left) and Sharon Tube Executive William Perrine review the operations of the gas-fired annealing furnace behind them that will use substantial additional natural gas volumes.* cial and industrial customers will help open a new avenue for the sale of natural gas.* These progressive projects are only some of the outgrowth of our concern for our Company, our customers, and our investors. We also provide strong support for eco- nomic development initiatives aimed at attracting new business to western New York and northwestern Pennsylvania. Partnering with economic initiatives helps bring new vitality and greater prosperity to these regions.* We are justifiably proud of our record of customer service performance in both our New York and Pennsylvania service territories. We keep 99.0% of all field appoint- ments, answer 84.9% of all calls within 30 seconds, and install 99.7% of new services within 10 days. These are important indicators that we do our job well. At left: As part of main and service line improvements and replacements during the past year, the Utility replaced three miles of six-inch steel pipe with eight-inch high density plas- tic pipe in the Wellsville, New York service area. Here Utility employee Gerald Weber, (center) works with a crew on a steep embankment along the pipeline’s route. Fiscal 2000 Weather Utility Operation and Maintenance Expense 2.1 .9 Percent Colder (Warmer) COLDER Than Normal Than Last Year WARMER 194 201 Millions of Dollars 187 184 182 173 (8.9) (9.2) 1995 1996 1997 1998 1999 2000 Buffalo, New York Erie, Pennsylvania 9 At Edinboro College in Pennsylvania, President Dr. Frank G. Pogue, (left) and Utility employee Les Young discuss a campus-wide energy plan to convert campus buildings from electric to natural gas energy. Buildings in the background include the new Arts and Sciences Center at the right. CANADA Lake Ontario T R A N S C A N A D A P I P E L I N E S LT D . E M P I R E S TAT E P I P E L I N E Buffalo Lake Erie NY VT T R A N S M I S S I O N I N C . M IN IO N D O MA CT TENNESSEE GAS PIPELINE COMPANY G A S T R A N S M I S S I O N C O R P. PA C O L U M B I A T E X A S E A S T E R N T R A N S M I S S I O N C O R P. Supply Corporation: Storage Areas System Pipelines NTINENTAL NSCO TRA P . R O E C E L I N S P I P A G NJ Capital expenditures are expected to drop over 10% in fiscal 2001.* Operating expenses decreased 5% during fiscal 2000. Since 1994 we have reduced manpower by approximately 26%, largely by offering early retirement packages. We have consolidated offices, warehouses, and other facilities, and now maintain only two call centers - one each in New York and Pennsylvania. Achieving these cost savings with no decrease in reliability or standards of service is the result of the effi- ciency of our employees and the implementation of new technologies. Technology is enabling us to do our work more effectively, and progressive multi-year rate settlements provide incentives that continue to benefit both our customers and shareholders. Pipeline and Storage The “desire” for natural gas, as measured by the prices people are willing to pay for this commodity, has never been greater. Not only do we see record high levels nationally as traded on the New York Mercantile Exchange, but in some selective markets, such as the entire state of California, natural gas prices are even higher. While these prices create certain difficulties for consumers, they are proof that our nation needs more gas produc- tion and more pipeline capacity to get supplies of natural gas to market. Our Exploration and Production segment is already benefiting from our belief in the need for additional gas supplies. Our Pipeline and Storage segment should also do so soon.* Total throughput increased slightly from last year, but fiscal 2000 earnings of $31.6 million, or $.81 per share, decreased $8.2 million from fiscal 1999 earnings. The addition of a New York State income tax as part of recently enacted tax law changes plus increased operating and maintenance costs contributed to lower earnings. Several items in fiscal 1999 did not recur in fiscal 2000, which also contributed to 2000 earnings being less than 1999 earnings. Our Pipeline and Storage segment is preparing for changes in the natural gas market by taking advantage of our unique geographic location between Canada and the Leidy, Pennsylvania market hub which serves the rapidly growing eastern U.S. markets. In fiscal 2000 approximately one-half of this segment’s transportation throughput consisted of deliveries to interconnecting pipelines, with the remainder delivered to National Fuel Gas Distribution Corporation. Our focus for expansion is to increase transportation capacity through our system into Leidy.* For nearly three years, as a one-third partner in the Independence Pipeline project, we have been championing the need for additional pipeline capacity to move gas from the Chicago area to the East Coast. The recently completed Alliance Pipeline will bring large additional volumes from Canada into Chicago. Clearly, additional volumes are still needed on the East Coast, but, while we stand ready and able to build Independence with the nec- essary regulatory approvals, the potential customers have not yet signed the contracts we 10 The XM-10 pipeline interconnection in Above: A crew welds the pipe before Pendleton, New York, between our it gets placed in the trench. Line X and the Empire State Pipeline Right: An epoxy paint coating is also consists of approximately four miles applied to the welded joints to of 16-inch steel pipe, and will protect them from corrosion. enhance gas supply sources as well Far right: A hydrostatic safety test is as increase system reliability.* conducted to test the strength of Measurement and regulation/flow the pipe and the welds. Here, Supply control facilities on this pipeline were Corporation employee Joseph designed to hold more than four Schuster (left) and Public Service times the operating pressure and to Commission Inspector James Williams move up to 150 million cubic feet of monitor the results. gas per day onto Line X. 11 seek to assure that the Independence Pipeline is an economic success. The current cold winter should encourage potential shippers to sign up for firm transportation capacity.* Since we are unwilling to pin all of our hopes on a single effort, our Pipeline and Storage segment is exploring with a potential partner the feasibility of jointly offering a new transportation service from southern Ontario (where the new Vector Pipeline and available capacity on existing pipelines should bring additional volumes from Chicago and Alberta) to our hub at Leidy, Pennsylvania.* This project would provide a new alternative for Canadian gas supplies to reach the rapidly growing Eastern markets. Last year’s capital projects included the installation of Line XM- 10, a four-mile pipeline connecting the Empire State Pipeline with our Line X. Estimated total capital expenditures for the Pipeline and Storage segment in fiscal 2001 of over $38 million will be concen- trated on reconditioning storage wells, replacing storage and transmis- sion lines, and increasing compressor horsepower.* For example, a 14- mile section of our pipeline system in northwestern Pennsylvania is being replaced with larger diameter pipe, to be known as Line AM-60. This will improve our system flexi- bility and provide greater quantities of natural gas to our Erie, Pennsylvania market.* As the natural gas market changes, the value of traditional storage service has come under pressure. Accordingly, we are meeting this challenge by offering new shorter term and market priced services to gas marketers. While these programs have been success- ful, it remains difficult to extract full value from our storage resources. We expect that as the market rationalizes, storage capacity value once again will be fully recognized and our storages will provide a large contribution to the system.* Our plans to enhance our storage deliverability include making added investments in our better fields and abandoning some of our smaller, less strategic fields.* Additionally, we have identified new storage opportunities, and, when the market requires added volume, we will be in a position to provide it.* Over the next few years, changes in natural gas markets will cause significant adjust- ments to be made in the Pipeline and Storage segment of our business.* We recognize The hydraulic fracturing process increased the injection and with- drawal capabilities of this Supply Corporation storage well near our Nashville Station by fivefold. Pictured above, a temporary valve “stinger assembly” is installed to protect the permanent wellhead and master valve from possible damage from the large volumes of sand and water that are pumped into the well during the fracturing process. that these changes are coming and believe we are positioned well to profit from them.* Lake Erie NY Timber The timber from the 140,000 acres we own in Pennsylvania and New York continues to attract buyers from all over the world, but particularly from Germany and Japan. The rich stands of cherry are especially in demand as our trees are among the finest for use as veneer in furniture manufacturing. The growth of a mature cherry tree is a lengthy process, taking approximately 100 years. Many of our trees are nearing that maturity, and during the last five years we have focused on enhancing our capabilities PA Seneca Acreage Sawmills At right: A forester measures a tree’s diameter as part of a timber cruise in a forest near Marienville, Pennsylvania. The Timber segment is in the midst of conducting a two-year forest inventory to estimate the board-foot assets of its to harvest expeditiously as our crop “ripens.” For example, in the last five years we have acreage. 12 13 expanded our annual sawmill capacity from 5.5 to12.9 million board feet. In fiscal 1996 we logged 6.4 million board feet which increased to 24.6 million board feet in fiscal 2000, and we are targeting nearly 28.0 million board feet in fiscal 2001.* Net income for this segment grew commensurately from $1.6 million or $.04 per share in fiscal 1996 to $6.1 million or $.16 per share in fiscal 2000. Highland operates a total of seven kilns in Kane and Marienville, Pennsylvania, with a total annual drying capacity of 420,000 board feet. Here, red oak is stacked in a sixty-five thousand board-foot kiln in prepara- tion for a 28-day drying process. A minor but clear example of the synergies we enjoy among our various segments was the utilization of our exploration and production expertise to drill a successful gas well on the grounds of our Marienville, Pennsylvania plant. The gas is used to fuel a recently constructed lumber drying kiln. With dramatically rising gas prices and our focus of controlling operating expenses, our decision to drill this well looks better and better. Timber Production Board Feet in Millions 24.6 21.2 13.1 9.8 6.4 We continue to be engaged in the lengthy process of completely “cruising” or 1996 1997 1998 1999 2000 GERMANY UE CZECH REPUBLIC POLAND TK SLOVAKIA AUSTRIA Horizon Energy taking inventory of our standing timber. The end result will be detailed maps of our timber types, growing sites, topography, and road system which will enable us to more effectively manage this asset.* International Horizon Energy Development, Inc. (Horizon), which manages our international enterprises, provided 2.6% of the Company’s total earnings in fiscal 2000. Specifically, Horizon contributed earnings of $3.3 million, or $.08 per share, an increase of $1 million over fiscal 1999 earnings. This year was principally marked by the merger of our two primary international holdings - Severoc˘eské teplárny, a.s. (SCT), a steam heating company in the North Bohemian Region of the Czech Republic, and První severozápadní teplárenska, a.s. (PSZT), a wholesale electric generator/steam heating company in the same region. The merger created the third- largest energy supplier in the Czech Republic, with approximately $200 million in combined assets. This combined company continues to realize manpower reductions and has sold non-core assets in order to further reduce costs and increase margins. The new company, United Energy, a.s., has adopted a distinctive green logo that reflects its environmentally responsible practices. During the past year we have invested in the equipment required to bring the company’s plants into compliance with international standards for minimizing atmospheric effluent. Given supply and price constraints in the Czech Republic, the cleaner choice of natural gas is currently not an option for powering the plants. For this reason, we have invested in new boiler technology that will continue to One of eight steam turbine generators at our Komor´any, Czech Republic power and heat plant which is capable of island performance and blackstart. 14 utilize indigenous coal that is available from the mine directly adjacent to our property. Additionally, we have upgraded our electric generation operations to prepare for com- petition in the “new” electric market. For example, our capability to operate in isola- tion from the local distribution grid during an electric outage (called “island perform- ance”) and then energize the grid to restore power once the grid problem has been identified and stabilized (called “blackstart”) will demand a premium delivery rate.* While this takes place, we will continue to look at additional prospects throughout eastern and central Europe and build a network of reliable contacts in the host country to lay the groundwork for stable and profitable partnerships.* Energy Marketing The Energy Marketing segment incurred a loss for fiscal 2000 of $7.8 million, or $.20 per share, after nearly nine years of profits. The main reasons for this loss were the Lake Ontario NY CANADA Lake Erie PA marking-to-market of certain derivative financial instruments and the accrual of a loss National Fuel Resources contingency on the unhedged portion of this segment’s fixed price sales contracts for the sale of natural gas to customers in 2001. The derivative financial instruments subject to mark-to-market accounting and leading to these losses have been closed, appropriate NFR Number of Customers management changes have been made, and new personnel and controls have been put in place to ensure future hedging activity is in compliance with accounting standards.* Looking forward, we are focusing on our historically profitable activities, secure in the knowledge that our experienced team of marketing professionals can maintain our profitable niche of providing quality service and savings to our more than 33,000 customers.* This segment continues to pursue new ways of providing service to its industrial and commercial customers by offering special services to help those customers lower NJ 33,115 17,480 5,476 672 1996 1,307 1997 1998 1999 2000 Electric Residential Gas Commercial / Industrial Gas their energy costs. We have invested approximately $1 million in a program that Natural Gas Marketing Volumes replaces out-moded and inefficient lighting fixtures in commercial establishments with high-efficiency lighting. This retrofitting package, available to customers when they sign on for long-term gas service with National Fuel Resources, Inc. results in a reduc- tion in electric bills which will offset the customer’s expenses for purchase and installa- 34.5 35.5 Bcf 26.5 20.2 21.0 tion; even greater savings can be expected over the long term.* 1996 1997 1998 1999 2000 Other Business In National Fuel as a whole, we have assembled a team of specialists from such fields as accounting, taxation, legal affairs, engineering, finance, and operations. This cadre of professionals conducts intensive investigations of prospective investments and acquisi- tions, both internationally and at home, and is responsible for both our Czech electric generation and our U.S. electric ventures. 15 NFR Power, Inc. (NFR Power), a National Fuel subsidiary, has entered into a part- nership that focuses on increasing profits through the use of environmentally beneficial power generation. In March of 2000, the company purchased a 50% interest in a gas processing facility located in Waterloo, New York. This facility draws methane gas from an adjacent landfill, filters it, and uses it as a fuel to generate and sell electricity to energy marketers in New York State. NFR Power has also entered discussions concerning the possibility of creating a similar plant, consisting of up to seven engines, at a site in Lewiston, New York. Under the proposed agreement, NFR Power would invest in an existing physical plant and share in profits from the sale of electricity to a local electric utility.* Our success in the energy industry, now and in the future, continues to result from the extraordinary efforts of the men and women who define this company. We are privileged to head a team of loyal, capable people who understand the direct relationship between the measure of their efforts and the strength of National Fuel. Our customers also value those efforts and the dependable service we continue to provide. Several important management changes have taken place this past year. John F. Riordan, who enjoys a much respected reputation in the natural gas industry, was elected to the Board of Directors of National Fuel Gas Company, filling a vacancy created upon George H. Schofield’s retirement last February. Dennis J. Seeley was elected to replace our friend and colleague, Richard Hare, upon his retirement as President of National Fuel Gas Supply Corporation. This past autumn, Robert J. Wright and Roger W. Wilcox, Vice Presidents of National Fuel Gas Distribution Corporation, retired after 24 and 36 years of service, respectively. In addition, Bruce D. Heine and Jay W. Lesch were each appointed Assistant Vice President of National Fuel Gas Distribution Corporation, and Duane A. Wassum was appointed Assistant Vice President of Horizon Energy Development, Inc. Bruce’s responsibilities include forecasting gas supply needs and coordinating transportation activities. Jay oversees the company’s customer service field operations in Western New York. Duane continues to monitor our operations in the Czech Republic. Fiscal 2001 holds great promise for our Company. We are excited as we approach the centennial of National Fuel Gas Company, a milestone not only for your Company but also for the energy industry. We look forward to welcoming that event by once again achieving record earnings and continuing our commitment to increasing shareholder value by buying and building real assets for the future.* Bernard J. Kennedy Chairman of the Board and Chief Executive Officer January 4, 2001 16 Philip C. Ackerman President NFR Power owns a 50% interest in this 11.2 megawatt power plant located in Waterloo, New York. This facility generates electricity from methane gas collected from the adjacent Seneca Meadows landfill (in the background). Note: This document contains “forward-looking statements” as defined by the Private Securities Litigation Reform Act of 1995. Forward- looking statements, including those designated by a “* ”, should be read with the cautionary statements and important factors included in this combined Annual Report and Form 10-K at Item 7 of the Form 10-K, under the heading “Safe Harbor for Forward-Looking Statements.” NATIONAL FUEL GAS COMPANY UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-K Annual Report Pursuant to Section 13 or 15(d) of The Securities Exchange Act of 1934 For the Fiscal Year Ended September 30, 2000 Commission File Number 1-3880 National Fuel Gas Company (Exact name of registrant as specified in its charter) New Jersey (State or other jurisdiction of incorporation or organization) 10 Lafayette Square Buffalo, New York (Address of principal executive offices) 13 -1086010 (I.R.S. Employer Identification No.) 14203 (Zip Code) (716) 857-7000 Registrant’s telephone number, including area code Securities registered pursuant to Section 12(b) of the Act: Title of each class Common Stock, $1 Par Value, and Common Stock Purchase Rights Name of each exchange on which registered New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: 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 and (2) has been subject to such filing requirements for the past 90 days. YES — ✔ 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 the 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. [ ✔ ] The aggregate market value of the voting stock held by nonaffiliates of the registrant amounted to $2,207,381,000 as of November 30, 2000. Common Stock, $1 Par Value, outstanding as of November 30, 2000: 39,384,950 shares. DOCUMENTS INCORPORATED BY REFERENCE Portions of the registrant’s Annual Report to Shareholders for 2000 are incorporated by reference into Part I of this report. Portions of the registrant’s definitive Proxy Statement for the Annual Meeting of Shareholders to be held February 15, 2001 are incorporated by reference into Part III of this report. 17 NATIONAL FUEL GAS COMPANY Part I Contents ITEM 1 Business The Company and its Subsidiaries 19 Rates and Regulation 21 The Utility Segment 21 The Pipeline and Storage Segment 22 The Exploration and Production Segment 22 The International Segment 22 The Energy Marketing Segment 22 The Timber Segment 22 Sources and Availability of Raw Materials 23 Competition 23 Seasonality 25 Capital Expenditures 25 Environmental Matters 25 Miscellaneous 26 Executive Officers of the Company 26 ITEM 2 Properties General Information on Facilities 27 Exploration and Production Activities 28 Legal Proceedings 29 Submission of Matters to a Vote of Security Holders 29 For the Fiscal Year Ended September 30, 2000 K - 0 1 m r o F ITEM 3 ITEM 4 ITEM 5 ITEM 6 ITEM 7 Market for the Registrant’s Common Stock and Related Shareholder Matters 29 Selected Financial Data 30 Management’s Discussion and Analysis of Financial Condition and Results of Operations 31 ITEM 7A Quantitative and Qualitative Disclosures About Market Risk 57 ITEM 8 ITEM 9 ITEM 10 ITEM 11 ITEM 12 ITEM 13 Financial Statements and Supplementary Data 57 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 89 Directors and Executive Officers of the Registrant 89 Executive Compensation 89 Security Ownership of Certain Beneficial Owners and Management 90 Certain Relationships and Related Transactions 90 ITEM 14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K 90 SIGNATURES 93 Part II Part III Part IV 18 NATIONAL FUEL GAS COMPANY This combined Annual Report to Shareholders/Form 10-K contains “forward-looking statements” as defined by the Private Securities Litigation Reform Act of 1995. Forward-looking statements should be read with the cautionary statements included in this combined Annual Report to Shareholders/Form 10-K at Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A), under the heading “Safe Harbor for Forward-Looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including, without limitation, those statements that are designated with a “*” following the statement, as well as those statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions. Part I I T E M•1 Business and its The Company Subsidiaries National Fuel Gas Company (the Company or Registrant), a registered holding company under the Public Utility Holding Company Act of 1935, as amended (the Holding Company Act), was organized under the laws of the State of New Jersey in 1902. The Company is engaged in the business of owning and holding securities issued by its twelve directly owned subsidiary companies. Except as otherwise indicated below, the Company owns all of the outstanding securities of its subsidiaries. Reference to “the Company” in this report means the Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure. Also, all references to a certain year in this report relate to the Company’s fiscal year ended September 30 of that year unless otherwise noted. The Company is a diversified energy company consisting of six reportable business segments. 1. The Utility segment operations are carried out by National Fuel Gas Distribution Corporation (Distribution Corporation), a New York corporation. Distribution Corporation sells natural gas or provides natural gas transportation services to approximately 735,000 customers through a local distribution system located in western New York and northwestern Pennsylvania. The principal metropolitan areas served by Distribution Corporation include Buffalo, Niagara Falls and Jamestown, New York and Erie and Sharon, Pennsylvania. 2. The Pipeline and Storage segment operations are carried out by National Fuel Gas Supply Corporation (Supply Corporation), a Pennsylvania corporation, and by Seneca Independence Pipeline Company (SIP), a Delaware corporation. Supply Corporation provides interstate natural gas transportation and storage services for affiliated and nonaffiliated companies through (i) an integrated gas pipeline system extending from southwestern Pennsylvania to the New York-Canadian border at the Niagara River and (ii) 28 underground natural gas storage fields owned and operated by Supply Corporation as well as four other underground natural gas storage fields operated jointly with various other interstate gas pipeline companies. SIP holds a one-third general partnership interest in Independence Pipeline Company (Independence), a Delaware general partnership. Independence, upon securing sufficient customer interest, plans to construct and operate the Independence Pipeline, a 400-mile interstate pipeline system expected to transport about 916 thousand dekatherms (MDth) per day of natural gas from Defiance, Ohio to Leidy, Pennsylvania.* 19 NATIONAL FUEL GAS COMPANY 20 3. The Exploration and Production segment operations are carried out by Seneca Resources Corporation (Seneca), a Pennsylvania corporation. Seneca is engaged in the exploration for, and the development and purchase of, natural gas and oil reserves in the Gulf Coast region of Texas and Louisiana, in California, in Wyoming, and in the Appalachian region of the United States. Also, exploration and production operations are conducted in the provinces of Manitoba, Alberta and Saskatchewan in Canada by Seneca’s wholly-owned subsidiary, National Fuel Exploration Corp. (NFE), an Alberta, Canada corporation. 4. The International segment operations are carried out by Horizon Energy Development, Inc. (Horizon), a New York corporation. Horizon engages in foreign and domestic energy projects through investments as a sole or substantial owner in various business entities. These entities include Horizon Energy Holdings, Inc., a New York corporation, which owns 100% of Horizon Energy Development B.V. (Horizon B.V.). Horizon B.V. is a Dutch company whose principal assets are majority ownership of (i) United Energy, a.s. (UE), a wholesale power and district heating company located in the northern part of the Czech Republic, which was formed from the merger of Severoc˘eské teplárny, a.s. and První severozápadní teplárenská, a.s., and (ii) Teplárna Krome˘r˘íz˘, a.s. (TK), a district heating company located in the southeast region of the Czech Republic. 5. The Energy Marketing segment operations are carried out by National Fuel Resources, Inc. (NFR), a New York corporation engaged in the marketing and brokerage of natural gas and electricity and the performance of energy management services for industrial, commercial, public authority and residential end-users in the northeast United States. 6. The Timber segment operations are carried out by Highland Forest Resources, Inc. (Highland), a Pennsylvania corporation (formerly known as Highland Land & Minerals, Inc.), and by a division of Seneca known as its Northeast Division. This segment markets timber from its New York and Pennsylvania land holdings, owns four sawmill operations in northwestern Pennsylvania and processes timber consisting primarily of high quality hardwoods. Financial information about each of the Company’s business segments can be found in Item 7, MD&A and also in Item 8 at Note I - Business Segment Information. The Company’s other wholly-owned subsidiaries are not included in any of the six reportable business segments and consist of the following: • Upstate Energy Inc. (Upstate), a New York corporation engaged in wholesale natural gas marketing and other energy-related activities; • Niagara Independence Marketing Company (NIM), a Delaware corporation which owns a one-third general partnership interest in DirectLink Gas Marketing Company (DirectLink), a Delaware general part- nership. DirectLink was formed to engage in natural gas marketing and related businesses in part by sub- scribing for firm transportation capacity on the Independence Pipeline (see Pipeline and Storage segment discussion below); • Leidy Hub, Inc. (Leidy), a New York corporation formed to provide various natural gas hub services to customers in the eastern United States; • Data-Track Account Services, Inc. (Data-Track), a New York corporation which provides collection services principally for the Company’s subsidiaries; and • NFR Power, Inc. (NFR Power), a New York corporation is designated as an “exempt wholesale generator” under the Holding Company Act and is developing or operating mid-range independent power production facilities. No single customer, or group of customers under common control, accounted for more than 10% of the Company’s consolidated revenues in 2000. NATIONAL FUEL GAS COMPANY Rates and Regulation The Company is subject to regulation by the Securities and Exchange Commission (SEC) under the broad regulatory provisions of the Holding Company Act, including provisions relating to issuance of securities, sales and acquisitions of securities and utility assets, intra-Company transactions and limitations on diversifi- cation. The SEC and some members of Congress have advocated, on either a stand-alone basis or in con- junction with legislation which would deregulate the electric industry, the repeal of the Holding Company Act. Thus far, the proposed legislation would transfer certain oversight responsibilities to the various state public utility regulatory commissions and the Federal Energy Regulatory Commission (FERC) and would expand the access of these bodies to the books and records of companies in a holding company system and could increase regulation, especially at the state level.* By contrast, previous SEC rule changes have reduced the number of applications required to be filed under the Holding Company Act, exempted some routine financings and expanded diversification opportunities. The Company is unable to predict at this time what the ultimate outcome of legislative or regulatory changes will be and, therefore, what impact such efforts might have on the Company.* The Utility segment’s rates, services and other matters are regulated by the State of New York Public Service Commission (NYPSC) with respect to services provided within New York and by the Pennsylvania Public Utility Commission (PaPUC) with respect to services provided within Pennsylvania. For additional discussion of the Utility segment’s rates and regulation, see Item 7, MD&A under the heading “Rate Matters” and Item 8 at Note B - Regulatory Matters. The Pipeline and Storage segment’s rates, services and other matters are regulated by the FERC. SIP is not itself regulated by the FERC, but its sole business is the ownership of an interest in Independence, whose construction, rates, services and other matters are or will be regulated by the FERC. For additional discus- sion of the Pipeline and Storage segment’s rates and regulation, see Item 7, MD&A under the heading “Rate Matters” and Item 8 at Note B-Regulatory Matters. The discussion under Item 8 at Note B - Regulatory Matters includes a description of the regulatory assets and liabilities reflected on the Company’s Consolidated Balance Sheets in accordance with applicable accounting standards. To the extent that the criteria set forth in such accounting standards are not met by the operations of the Utility segment or the Pipeline and Storage segment, as the case may be, the related regulatory assets and liabilities would be eliminated from the Company’s Consolidated Balance Sheets and such accounting treatment would be discontinued. In the International segment, rates charged for the sale of thermal energy and electric energy at the retail level are subject to regulation and audit in the Czech Republic by the Czech Ministry of Finance. The regu- lation of electric energy rates at the retail level indirectly impacts the rates charged by the International segment for its electric energy sales at the wholesale level. In addition, the Company and its subsidiaries are subject to the same federal, state and local regulations 00000 on various subjects as other companies doing similar business in the same locations. The Utility Segment The Utility segment contributed approximately 45.3% of the Company’s net income available for common stock in 2000. During 2000, Distribution reached agreement with the Staff of the New York Department of Public Service, the New York State Consumer Protection Board, and Multiple Intervenors (an advocate for large commercial and industrial customers), that settles rates for a three year period beginning with 2001. Additional discussion of the Utility segment appears below in this Item 1 under the headings “Sources and Availability of Raw Materials,” “Competition” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data. 21 NATIONAL FUEL GAS COMPANY The Pipeline and Storage Segment 00000 The Exploration and Production Segment 00000 The Pipeline and Storage segment contributed approximately 24.9% of the Company’s net income available for common stock in 2000. Supply Corporation currently has service agreements for substantially all of its firm transportation capacity which totals approximately 1,839 MDth per day. The Utility segment has contracted for approxi- mately 1,149 MDth per day or 62.5% of that capacity until 2003 and continuing year-to-year thereafter. An additional 536 MDth per day or 29.1% of Supply Corporation’s firm transportation capacity is subject to firm contracts with nonaffiliated customers until 2003 or later. Supply Corporation has available for sale to customers approximately 67,409 MDth of firm storage capacity. The Utility segment has contracted for 28,248 MDth or 41.9% of that capacity. Of that, 26,581 MDth or 39.4% of total storage capacity is contracted by the Utility segment under agreements with remaining initial terms expiring in 2003 or later. Other customers, both affiliated and nonaffiliated, have contracted for the remaining 39,161 MDth or 58.1% of firm storage capacity, and 15,276 MDth or 22.7% of total storage capacity is contracted by nonaffiliated customers until 2003 or later. Supply Corporation has been successful in marketing and obtaining executed contracts for storage service (at discounted rates) as it becomes available and expects to continue to do so.* Additional discussion of the Pipeline and Storage segment appears below under the headings “Sources and Availability of Raw Materials,” “Competition” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data. The Exploration and Production segment contributed approximately 27.4% of the Company’s net income available for common stock in 2000. In June 2000, Seneca, through its wholly-owned subsidiary, NFE, acquired the stock of Tri Link Resources Ltd., a Calgary, Alberta-based exploration and production company for approximately $123.8 million (and another $99.2 million in assumed debt which has been redeemed). Upon completing this acquisition, Tri Link was amalgamated into NFE. This acquisition increased Seneca’s total reserve base to approximately one trillion cubic feet equivalent.* Additional discussion of the Exploration and Production segment appears below under the headings “Sources and Availability of Raw Materials” and “Competition,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data. The International Segment The International segment contributed approximately 2.6% of the Company’s net income available for common stock in 2000. Additional discussion of the International segment appears below under the heading “Sources and Availability of Raw Materials,” “Competition” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data. The Energy Marketing segment incurred a net loss in 2000. The impact of this segment’s net loss in relation to total net income for the Company was negative 6.1%. Additional discussion of the Energy Marketing segment appears below under the headings “Sources and Availability of Raw Materials,” “Competition” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data. 00000 The Energy Marketing Segment 00000 The Timber Segment The Timber segment contributed approximately 4.8% of the Company’s net income available for common stock in 2000. Additional discussion of the Timber segment appears below under the headings “Sources and Availability of Raw Materials,” “Competition” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data. 22 NATIONAL FUEL GAS COMPANY Sources and Availability of Raw Materials Natural gas is the principal raw material for the Utility segment. In 2000, the Utility segment purchased 104.0 billion cubic feet (Bcf) of gas. Gas purchases from various producers and marketers in the southwest- ern United States and Canada under long-term (two years or longer) contracts accounted for 71% of these purchases. Purchases of gas on the spot market (contracts of less than a year) accounted for 28% of the Utility segment’s 2000 gas purchases. Gas purchases from Dynegy Marketing and Trade and BP Energy Co. (both providing gas from the southwestern United States under long-term contracts) represented 28% and 20%, respectively, of total 2000 gas purchases by the Utility segment. No other producer or marketer pro- vided the Utility segment with 10% or more of its gas requirements in 2000. Supply Corporation transports and stores gas owned by its customers, whose gas originates in the south- western and Appalachian regions of the United States as well as in Canada. SIP, through Independence, proposes to transport natural gas produced in Canada and in the continental United States. The Exploration and Production segment seeks to discover and produce raw materials (natural gas, oil and hydrocarbon liquids) as further described in this report in Item 7, MD&A and Item 8 at Notes I - Business Segment Information and M - Supplementary Information for Oil and Gas Producing Activities. Coal is the principal raw material for the International segment, constituting 45% of the cost of raw materials needed to operate the boilers which produce steam or hot water. Natural gas, oil, limestone and water combined account for the remaining 55% of such materials. Coal is purchased and delivered directly from the Mostecka Uhelna Spolecnost, a.s. mine for Horizon’s largest coal-fired plant under a contract where price and quantity are the subject of negotiation each year. Based on the current extraction rate, this mine has proven reserves through 2030. Natural gas is imported by the Czech Republic government from Russia and the North Sea and is transported through the Transgas pipeline system which is majority owned by the Czech government and purchased by the International segment from two of the eight regional gas distribu- tion companies. Oil is also imported. This segment purchases oil from domestic and foreign refineries. With respect to the Timber segment, Highland requires an adequate supply of timber to process. Highland, however, mainly processes timber which is located on land owned by Seneca, and, therefore, the source and availability of this segment’s primary raw material are generally known in advance. The Energy Marketing segment depends on an adequate supply of natural gas and electricity. In 2000, 00000 this segment purchased 35.5 Bcf of natural gas and approximately 57,000 megawatt hours of electricity. Competition Competition in the natural gas industry exists among providers of natural gas, as well as between natural gas and other sources of energy. The continuing deregulation of the natural gas industry should enhance the competitive position of natural gas relative to other energy sources, such as fuel oil or electricity, by removing some of the regulatory impediments to adding customers and responding to market forces.* In addition, the environmental advantages of natural gas compared with other fuels should increase the role of natural gas as an energy source.* Moreover, while demand for natural gas is increasing, the production of natural gas also continues to increase making it a dependable alternative to imported oil.* The electric industry is moving toward a more competitive environment as a result of the Federal Energy Policy Act of 1992 and initiatives undertaken by the FERC and various states. It is unclear at this point what impact this restructuring will have on the Company.* The Company competes on the basis of price, service and reliability, product performance and other factors. Sources and providers of energy, other than those described under this “Competition” heading, do not compete with the Company to any significant extent.* 23 Competition: The Utility Segment The changes precipitated by the FERC’s restructuring of the gas industry in Order No. 636 are redefining the roles of the gas utility industry and the state regulatory commissions. Regulators in both New York and Pennsylvania have adopted retail competition for natural gas supply purchases. However, the Utility segment’s traditional distribution function remains largely unchanged. For further discussion of state restruc- turing initiatives refer to Item 7, MD&A under the heading “Rate Matters.” Competition for large-volume customers continues with local producers or pipeline companies attempt- ing to sell or transport gas directly to end-users located within the Utility segment’s service territories (i.e., bypass). In addition, competition continues with fuel oil suppliers and may increase with electric utilities making retail energy sales.* The Utility segment is now better able to compete, through its unbundled flexible services, in its most vulnerable markets (the large commercial and industrial markets).* The Utility segment continues to (i) develop or promote new sources and uses of natural gas or new services, rates and contracts and (ii) emphasize and provide high quality service to its customers. Competition: The Pipeline and Storage Segment Supply Corporation competes for market growth in the natural gas market with other pipeline companies transporting gas in the northeastern United States and with other companies providing gas storage services. Supply Corporation has some unique characteristics which enhance its competitive position. Its facilities are located adjacent to Canada and the northeastern United States and provide part of the link between gas-con- suming regions of the eastern United States and gas-producing regions of Canada and the southwestern, southern and other continental regions of the United States. This location offers the opportunity for increased transportation and storage services in the future.* SIP, through Independence, is competing for customers with other proposed pipeline projects which would bring natural gas from the Chicago area to the growing markets in the northeast and mid-Atlantic regions of the United States. In combination with expansion projects of Transcontinental Gas Pipe Line Corporation and ANR Pipeline Company, Independence intends to provide the least-cost path for this service and will access the storage and market hub at Leidy, Pennsylvania.* It is likely that not all of the pro- posed pipelines will go forward, and that the first project built will have an advantage over other proposed projects.* Independence is the first of the proposed projects to be approved by the FERC. If completed, the Independence pipeline would likely create opportunities for increased transportation and storage services by Supply Corporation.* Competition: The Exploration and Production Segment The Exploration and Production segment competes with other gas and oil producers and marketers with respect to its sales of oil and gas. The Exploration and Production segment also competes, by competitive bidding and otherwise, with other oil and natural gas exploration and production companies of various sizes for leases and drilling rights for exploration and development prospects. To compete in this environment, Seneca and its wholly-owned subsidiary, NFE, each originate and act as operator on most prospects, minimize risk of exploratory efforts through partnership-type arrangements, apply the latest technology for both exploratory studies and drilling operations and focus on market niches that suit its size, operating expertise and financial criteria. NATIONAL FUEL GAS COMPANY 24 NATIONAL FUEL GAS COMPANY Competition: The International Segment Horizon competes with other entities seeking to develop foreign and domestic energy projects. Horizon, through UE, faces competition in the sale of thermal energy to large industrial customers. Currently, electric energy sales are made to the regional electric distribution company. The Czech cabinet approved a plan put forward by the Ministry of Industry and Trade to privatize the Czech Republic’s dominant energy producer and six regional electric distributors. It is unclear at this point what impact this privatization will have on the wholesale electric energy market.* UE sells electricity at the wholesale level. Competition: The Energy Marketing Segment The Energy Marketing segment competes with other marketers of electricity and natural gas and with other providers of energy management services. Although the deregulation of electric and natural gas utilities is a relatively new occurrence, the competition in this area is well developed with regard to price and services and derives from both local and regional marketers. Competition: The Timber Segment With respect to the Timber segment, Highland competes with other sawmill operations and with other sup- pliers of timber. These competitors may be local, regional, national or international in scope. This competi- tion, however, is primarily limited to those entities which either process or supply high quality hardwoods species such as cherry, oak and maple as veneer, saw logs or export logs ultimately used in the production of high-end furniture, cabinetry and flooring. The Timber segment markets its products both nationally and internationally. Variations in weather conditions can materially affect the volume of gas delivered by the Utility segment, as virtually all of its residential and commercial customers use gas for space heating. The effect on the Utility segment in New York is mitigated by a weather normalization clause which is designed to adjust the rates of retail customers to reflect the impact of deviations from normal weather. Weather that is more than 2.2% warmer than normal results in a surcharge being added to customers’ current bills, while weather that is more than 2.2% colder than normal results in a refund being credited to customers’ current bills. In the International segment, district heating operations in the Czech Republic are also subject to the seasonality of weather. Volumes transported and stored by Supply Corporation may vary materially depending on weather, without materially affecting its earnings. Supply Corporation’s rates are based on a straight fixed-variable rate design which allows recovery of all fixed costs in fixed monthly reservation charges. Variable charges based on volumes are designed only to reimburse the variable costs caused by actual transportation or storage of gas. Variations in weather conditions can materially affect the volume of gas and electricity consumed by customers of the Energy Marketing segment. The activities of the Timber segment vary on a seasonal basis and are subject to weather constraints. The timber harvesting and processing season occurs when timber growth is dormant and runs from approxi- mately September to March. The operations conducted in the summer months focus on pulpwood and on thinning out lower-grade species from the timber stands to encourage the growth of higher-grade species. 00000 Seasonality 00000 Capital Expenditures A discussion of capital expenditures by business segment is included in Item 7, MD&A under the heading “Investing Cash Flow.” Environmental Matters A discussion of material environmental matters involving the Company is included in Item 7, MD&A under the heading “Other Matters” and in Item 8, Note H - Commitments and Contingencies. 25 NATIONAL FUEL GAS COMPANY Miscellaneous 00000 The Company and its wholly-owned subsidiaries had a total of 3,597 full-time employees at September 30, 2000, 2,396 employees in all of its U.S. operations and 1,201 employees in its International segment. This is a decrease of 5.5% from the 3,807 total employed at September 30, 1999. Agreements covering employees in collective bargaining units in New York were renegotiated in November 2000, effective beginning on November 26, 2000, and are scheduled to expire in February 2006. Agreements covering most employees in collective bargaining units in Pennsylvania were renegotiated, effec- tive November 1998, and are scheduled to expire in April and May 2003. The Company has numerous municipal franchises under which it uses public roads and certain other rights-of-way and public property for the location of facilities. When necessary, the Company renews such franchises. Executive Officers Name and Age (2) Current Company Positions and Other Material Business Experience During Past 5 Years (3) of the Company as of November 15, 2000(1) Bernard J. Kennedy (69) Chairman of the Board of Directors since March 1989 and Chief Executive Officer since August 1988. Mr. Kennedy has served as a Director since March 1978 and previously served as President from January 1987 to July 1999. Philip C. Ackerman (56) Dennis J. Seeley (57) David F. Smith (47) James A. Beck (53) Joseph P. Pawlowski (59) Gerald T. Wehrlin (62) President since July 1999, Executive Vice President of Supply Corporation since October 1994 and President of Horizon since September 1995. Mr. Ackerman has served as a Director since March 1994, and previously served as Senior Vice President from June 1989 to July 1999 and President of Distribution Corporation from October 1995 to July 1999. President of Supply Corporation since March 2000. Mr. Seeley has served as Vice President of the Company from January 2000 to April 2000, Senior Vice President of Distribution Corporation from February 1997 to March 2000 and Senior Vice President of Supply Corporation from January 1993 to February 1997. President of Distribution Corporation since July 1999. Mr. Smith served as Senior Vice President of Distribution Corporation from January 1993 to July 1999. President of Seneca since October 1996 and President of Highland since March 1998. Mr. Beck previously served as Vice President of Seneca from January 1994 to April 1995 and Executive Vice President of Seneca from May 1995 to September 1996. Treasurer since December 1980; Senior Vice President of Distribution Corporation since February 1992 and Treasurer of Distribution Corporation since January 1981; Treasurer of Supply Corporation since June 1985 and Secretary of Supply Corporation since October 1995. Controller since December 1980; Senior Vice President of Distribution Corporation since April 1991; Controller of Seneca since September 1981; Vice President of Horizon since February 1997. Mr. Wehrlin previously served as Secretary and Treasurer of Horizon from September 1995 to February 1997. Walter E. DeForest (59) Senior Vice President of Distribution Corporation since August 1993. Bruce H. Hale (51) Senior Vice President of Supply Corporation since February 1997 and Vice President of Horizon since September 1995. Mr. Hale previously served as Senior Vice President of Distribution Corporation from January 1993 to February 1997. (1) The Company has been advised that there are no family relationships among any of the officers listed, and that there is no arrangement or understanding among any one of them and any other persons pursuant to which he was elected as an officer. The executive officers serve at the pleasure of the Board of Directors. (2) Ages are as of September 30, 2000. (3) The information provided relates to the principal subsidiaries of the Company. Many of the executive officers have in the past or currently serve as officers or directors for other subsidiaries of the Company. 26 NATIONAL FUEL GAS COMPANY I T E M•2 Properties General Information on Facilities The investment of the Company in net property, plant and equipment was $2.7 billion at September 30, 2000. Approximately 53% of this investment is in the Utility and Pipeline and Storage segments, which are primarily located in western New York and western Pennsylvania. The Exploration and Production segment represents the next largest investment in net property, plant and equipment (37%) and is primarily located in the Gulf Coast region of Texas and Louisiana, in California, in Wyoming, in the Appalachian region of the United States and in the provinces of Manitoba, Alberta and Saskatchewan in Canada. The remaining investment in net property, plant and equipment consists primarily of the International segment (6%) which is located in the Czech Republic and the Timber segment (4%) which is located primarily in northwestern Pennsylvania. During the past five years, the Company has made significant additions to property, plant and equipment in order to expand and improve transmission and distribution facilities for both retail and trans- portation customers, to augment the reserve base of oil and gas in the United States and Canada, and to pur- chase district heating and power generation facilities in the Czech Republic. Net property, plant and equip- ment has increased $1.034 billion, or 63%, since 1995. The Utility segment has a net investment in property, plant and equipment of $939.8 million at September 30, 2000. The net investment in its gas distribution network (including 14,769 miles of distribu- tion pipeline) and its services represent approximately 57% and 29%, respectively, of the Utility segment’s net investment in property, plant and equipment at September 30, 2000. The Pipeline and Storage segment represents a net investment of $475 million in property, plant and equipment at September 30, 2000. Transmission pipeline, with a net cost of $131.1 million, represents 28% of this segment’s total net investment and includes 2,556 miles of pipeline required to move large volumes of gas throughout its service area. Storage facilities consist of 32 storage fields, four of which are jointly oper- ated with certain pipeline suppliers, and 478 miles of pipeline. Net investment in storage facilities includes $81.1 million of gas stored underground-noncurrent, representing the cost of the gas required to maintain pressure levels for normal operating purposes as well as gas maintained for system balancing and other pur- poses, including that needed for no-notice transportation service. The Pipeline and Storage segment has 29 compressor stations with 74,671 installed compressor horsepower. The Exploration and Production segment had a net investment in property, plant and equipment amounting to $998.9 million at September 30, 2000. Of this amount, $750.1 million relates to properties located in the United States. The remaining net investment of $248.8 million relates to properties located in Canada. The International segment had a net investment in property, plant and equipment amounting to $172.6 million at September 30, 2000. UE’s net investment in district heating and electric generation facili- ties was $171.8 million; and TK’s net investment in district heating facilities was approximately $0.7 million. The Timber segment had a net investment in property, plant and equipment of $95.6 million at September 30, 2000. Located primarily in northwestern Pennsylvania, the net investment includes four sawmills and approximately 150,000 acres of timber. The Utility and Pipeline and Storage segments’ facilities provided the capacity to meet its 2000 peak day sendout, including transportation service, of 1,779 million cubic feet (MMcf), which occurred on January 17, 2000. Withdrawals from storage of 779.5 MMcf provided approximately 43.8% of the require- ments on that day. Company maps are included throughout pages 3 through 16 of this combined Annual Report to Shareholders/Form 10-K and are incorporated herein by reference. 27 NATIONAL FUEL GAS COMPANY Exploration and Production Activities The information that follows is disclosed in accordance with SEC regulations, and relates to the Company’s oil and gas producing activities. A further discussion of oil and gas producing activities is included in Item 8, Note M - Supplementary Information for Oil and Gas Producing Activities. Note M sets forth proved developed and undeveloped reserve information for Seneca. Seneca’s oil and gas reserves reported in Note M as of September 30, 2000 were estimated by Seneca’s qualified geologists and engineers and were audited by independent petroleum engineers from Ralph E. Davis Associates, Inc. and McDaniel and Associates Consultants, Ltd. Seneca reports its oil and gas reserve information on an annual basis to the Energy Information Administration (EIA). The basis of reporting Seneca’s reserves to the EIA is identical to that reported in Note M. The following is a summary of certain oil and gas information taken from Seneca’s records. All mone- tary amounts are expressed in U.S. dollars. PRODUCTION For the Year Ended September 30 United States Average Sales Price per Mcf of Gas(1) Average Sales Price per Barrel of Oil(1) Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced Canada Average Sales Price per Mcf of Gas(1) Average Sales Price per Barrel of Oil(1) Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced Total Average Sales Price per Mcf of Gas(1) Average Sales Price per Barrel of Oil(1) Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced (1) Prices do not reflect gains or losses from hedging activities. 2000 1999 1998 $3.31 $25.34 $0.51 $2.52 $29.28 $1.41 $3.31 $26.03 $0.58 $2.20 $12.85 $0.46 — — — $2.20 $12.85 $0.46 $2.45 $12.15 $0.45 — — — $2.45 $12.15 $0.45 PRODUCTIVE WELLS At September 30, 2000 Productive Wells United States Gas 1,924 1,782 Oil 860 782 Canada Oil 471 427 Gas 8 3 Gas 1,932 1,785 Total Oil 1,331 1,209 – gross – net DEVELOPED AND UNDEVELOPED ACREAGE At September 30, 2000 Developed Acreage Undeveloped Acreage – gross – net – gross – net United States Canada Total 641,535 552,275 997,031 716,759 68,917 53,160 1,839,706 1,827,910 710,452 605,435 2,836,737 2,544,669 28 NATIONAL FUEL GAS COMPANY DRILLING ACTIVITY For the Year Ended September 30 United States Net Wells Completed Canada Net Wells Completed Total Net Wells Completed PRESENT ACTIVITIES At September 30, 2000 Wells in Process of Drilling Productive Dry 2000 1999 1998 2000 1999 1998 – Exploratory – Development – Exploratory – Development 13.89 82.82 1.00 21.50 12.95 95.26 10.72 14.11 — — — — – Exploratory – Development 14.89 104.32 12.95 95.26 10.72 14.11 6.53 1.00 — 4.00 6.53 5.00 5.64 4.75 — — 5.64 4.75 4.97 2.00 — — 4.97 2.00 United States Canada Total – gross – net 30.00 25.78 2.00 2.00 32.00 27.78 South Lost Hills Waterflood Program In Seneca’s South Lost Hills Field, a waterflood project was initiated in 1996 on the Ellis lease in the Diatomite reservoir for pressure maintenance and recovery enhancement purposes. Currently there are 26 injection wells and 91 production wells in the program. The total injection and production from this water- flood project are 6,400 barrels of water per day and 300 barrels of oil per day, respectively. I T E M•3 Legal Proceedings I T E M•4 Submission of Matters to a Vote of Security Holders No matter was submitted to a vote of security holders during the fourth quarter of 2000. For a discussion of various environmental matters, refer to Item 7, MD&A under the heading “Other Matters” and to Item 8 at Note H - Commitments and Contingencies. Part II I T E M•5 Market for the Registrant’s Common Stock and Related Shareholder Matters Information regarding the market for the Company’s common stock and related shareholder matters appears under Item 8 at Note D - Capitalization and Note L - Market for Common Stock and Related Shareholder Matters (unaudited). On July 1, 2000, the Company issued 840 unregistered shares of Company common stock to the seven non-employee directors of the Company, 120 shares to each such director. These shares were issued as partial consideration for the directors’ service as directors during the quarter ended September 30, 2000, pursuant to the Company’s Retainer Policy for Non-Employee Directors. These transactions were exempt from regis- tration under Section 4(2) of the Securities Act of 1933, as amended, as transactions not involving any public offering. 29 NATIONAL FUEL GAS COMPANY I T E M•6 Selected Financial Data Year Ended September 30 2000 1999 1998 1997 1996 Summary of Operations (Thousands) Operating Revenues Operating Expenses: Purchased Gas Fuel Used in Heat and Electric Generation Operation and Maintenance Property, Franchise and Other Taxes Depreciation, Depletion and Amortization Impairment of Oil and Gas Producing Properties Income Taxes Operating Income Other Income Income Before Interest Charges and Minority Interest in Foreign Subsidiaries Interest Charges Minority Interest in Foreign Subsidiaries Income Before Cumulative Effect Cumulative Effect of Change in Accounting $1,425,277 $1,263,274 $1,248,000 $1,265,812 $1,208,017 503,617 54,893 350,383 78,878 142,170 — 77,068 405,925 55,788 328,800 91,146 124,778 — 64,829 441,746 37,837 321,411 92,817 117,238 128,996 24,024 528,610 1,489 286,537 100,549 111,650 — 68,674 477,357 — 309,206 99,456 98,231 — 66,321 1,207,009 1,071,266 1,164,069 1,097,509 1,050,571 218,268 10,408 228,676 100,085 192,008 12,343 204,351 87,698 (1,384) (1,616) 127,207 — 115,037 — 83,931 35,870 119,801 85,284 (2,213) 32,304 (9,116) 168,303 3,196 171,499 56,811 — 114,688 — 157,446 3,869 161,315 56,644 — 104,671 — Net Income Available for Common Stock $ 127,207 $ 115,037 $ 23,188 $ 114,688 $ 104,671 Per Common Share Data Basic Earnings per Common Share Diluted Earnings per Common Share Dividends Declared Dividends Paid Dividend Rate at Year-End At September 30: Number of Common Shareholders Net Property, Plant and Equipment (Thousands) Utility Pipeline and Storage Exploration and Production International Energy Marketing Timber All Other Corporate Total Net Plant Total Assets (Thousands) Capitalization (Thousands) Common Stock Equity Long-Term Debt, Net of Current Portion Total Capitalization $3.25 $3.21 $1.89 $1.88 $1.92 $2.98 $2.95 $1.83 $1.82 $1.86 $0.61(1) $0.60(1) $1.77 $1.76 $1.80 $3.01 $2.98 $1.71 $1.70 $1.74 $2.78 $2.77 $1.65 $1.64 $1.68 21,164 22,336 23,743 20,267 21,640 $ 939,753 474,972 998,852 172,602 360 95,607 1,241 4 $ 919,642 466,524 674,813 210,920 489 88,623 214 7 $ 906,754 460,952 638,886 202,590 353 38,593 — 9 $ 889,216 450,865 443,164 942 123 34,872 173 11 $ 855,161 452,305 375,958 1,274 41 24,680 172 15 $2,683,391 $2,361,232 $2,248,137 $1,819,366 $1,709,606 $3,236,888 $2,842,586 $2,684,459 $2,267,331 $2,149,772 $987,437 953,622 $1,941,059 $ 939,293 822,743 $1,762,036 $ 890,085 693,021 $1,583,106 $ 913,704 581,640 $1,495,344 $ 855,998 574,000 $1,429,998 (1) 1998 includes oil and gas asset impairment of ($2.06) basic, ($2.04) diluted and cumulative effect of a change in depletion methods of ($0.24) basic and diluted. Refer to further discussion of these items in Notes to Financial Statements, Note A - Summary of Significant Accounting Policies. 30 NATIONAL FUEL GAS COMPANY I T E M•7 Management’s Discussion and Analysis of Financial Condition and Results of Operations WHERE IT CAME FROM: The Revenue Dollar – 2000 WHERE IT WENT TO: 40.5¢ Residential Gas Sales 15.1¢ Oil and Gas Production Revenues 11.3¢ Commercial, Industrial and Off-System Gas Sales 9.3¢ Energy Marketing Revenues 8.6¢ Gas Transportation Revenues 4.8¢ District Heating Revenues 2.7¢ Timber and Sawmill Revenues 2.2¢ Gas Storage Service Revenues 2.2¢ Electric Generation Revenues 3.3¢ Other Revenues 100.0¢ Total 34.9¢ Gas Purchased 14.0¢ Wages, Including Benefits 10.9¢ Other Materials and Services 10.7¢ Taxes 9.9¢ Depreciation 6.9¢ Interest 5.1¢ Dividends — Common Stock 3.8¢ Fuel Used in Heat and Electric Generation 3.7¢ Reinvested in the Business 0.1¢ Minority Interest in Foreign Subsidiaries 100.0¢ Total Results of Operations 2000 Compared with 1999 The Company’s earnings were $127.2 million, or $3.25 per common share ($3.21 per common share on a diluted basis) in 2000. This compares with 1999 earnings of $115.0 million, or $2.98 per common share ($2.95 per common share on a diluted basis). The increase in earnings of $12.2 million was the result of higher earnings in the Exploration and Production, Utility, Timber and International segments. These were offset in part by lower earnings in the Pipeline and Storage segment, the Energy Marketing segment (which had a loss for the year) and in Corporate operations. Additional discussion of earnings in each of the business segments can be found in the business segment information that follows. 1999 Compared with 1998 The Company’s earnings were $115.0 million, or $2.98 per common share ($2.95 per common share on a diluted basis), in 1999. This compares with 1998 earnings of $23.2 million, or $0.61 per common share ($0.60 per common share on a diluted basis). Earnings for 1998 included a $79.1 million (after tax) non- cash impairment of the Exploration and Production segment’s oil and gas assets and the non-cash cumulative effect of a change in accounting. The 1998 accounting change, which was a change in depletion methods for the Exploration and Production segment’s oil and gas assets, had a negative $9.1 million (after tax), or $0.24 per common share, non-cash cumulative effect through 1997, which was recorded in the first quarter of 1998. Excluding these two non-cash special items, earnings for 1998 would have been $111.4 million, or $2.91 per common share ($2.88 per common share on a diluted basis). The increase in 1999 earnings of $3.6 million (exclusive of the two non-cash special items in 1998) was the result of higher earnings in the Utility, Timber, Energy Marketing and International segments and in Corporate operations. These higher earnings were offset in part by reduced earnings in the Exploration and Production segment. The Pipeline and Storage segment’s earnings remained level with the prior year. 31 NATIONAL FUEL GAS COMPANY Additional discussion of earnings in each of the business segments can be found in the business segment information that follows. EARNINGS (LOSS) BY SEGMENT Year Ended September 30 (Thousands) Utility Pipeline and Storage Exploration and Production(1) International Energy Marketing Timber Total Reportable Segments All Other Corporate Total Consolidated(1) 2000 1999 1998 $57,662 31,614 34,877 3,282 (7,790) 6,133 125,778 (371) 1,800 $56,875 39,765 7,127 2,276 2,054 4,769 112,866 (162) 2,333 $51,788 39,852 (64,110) 1,279 787 1,904 31,500 143 661 $127,207 $115,037 $32,304 (1) Before Cumulative Effect of a Change in Accounting in 1998. Exclusive of the non-cash asset impairment, 1998 earnings for the Exploration and Production segment and Total Consolidated would have been $15,004 and $111,418, respectively. Utility Revenues UTILITY OPERATING REVENUES Year Ended September 30 (Thousands) 2000 1999 1998 Retail Revenues: Residential Commercial Industrial Off-System Sales Transportation Other UTILITY THROUGHPUT – (MMCF) Year Ended September 30 Retail Sales: Residential Commercial Industrial Off-System Sales Transportation $584,618 93,914 21,543 700,075 47,962 104,534 (6,112) $581,022 101,482 15,903 698,407 29,214 77,600 2,134 $612,647 123,807 18,068 754,522 44,479 62,844 9,335 $846,459 $807,355 $871,180 2000 1999 1998 68,196 12,312 4,276 84,784 12,833 71,862 71,177 13,885 4,144 89,206 12,469 64,086 71,704 16,405 4,298 92,407 16,192 60,080 169,479 165,761 168,679 32 NATIONAL FUEL GAS COMPANY 2000 Compared with 1999 Operating revenues for the Utility segment increased $39.1 million in 2000 compared with 1999. This resulted from an increase in retail, off-system, and transportation gas sales revenues of $1.7 million, $18.7 million, and $26.9 million, respectively. These increases were partly offset by a decrease in other operating revenues of $8.2 million. The increase in retail gas revenues for the Utility segment was primarily due to the recovery of higher gas costs, offset by a decrease in the volumes sold. The recovery of higher gas costs (gas costs are recovered dollar for dollar in revenues) resulted from a much higher cost of purchased gas. See further discussion of purchased gas below under the heading “Purchased Gas.” The decrease in retail sales volumes was primarily the result of the migration of residential and small commercial customers to transportation service in both the New York and Pennsylvania jurisdictions, offset slightly by the impact of colder weather. The migration from gas sales to transportation is the result of customers turning to marketers for their gas supplies while using the Utility for their gas transportation service. Restructuring in the Utility segment’s service territory is further discussed in the “Rate Matters” section that follows. Transportation revenues increased and volumes were up 7.8 billion cubic feet (Bcf) as a result of the migration noted above as well as the slightly colder weather. Off-system sales revenues increased largely due to increased gas prices and slightly higher volumes. However, due to profit sharing with retail customers, the margins resulting from off-system sales are minimal. The decrease in other operating revenues of $8.2 million was due primarily to a $9.7 million reduction in refund pool revenue, as discussed below, and an $8.5 million reduction in revenue for various adjustments (including a provision for refund) related to the September 30, 2000 conclusion of the two year rate settle- ment approved by the State of New York Public Service Commission (NYPSC). Partly offsetting these decreases were two items that reduced revenue in 1999 that did not recur in 2000. The more significant item was the gas restructuring reserve which reduced revenues by $7.2 million in 1999. This special reserve put aside dollars to be applied against incremental costs that could result from the NYPSC’s gas restructuring efforts and was required in 1999 by the terms of the rate settlement with the NYPSC. The NYPSC’s gas restructuring efforts are further discussed in the “Rate Matters” section that follows. The second item that reduced 1999 revenues was a $0.4 million adjustment related to the final settlement of Internal Revenue Service (IRS) audits. Also offsetting the decreases noted above, 2000 revenue includes $0.7 million accrued to offset additional state income taxes that resulted from the enactment of tax changes in New York State. The revenue and related regulatory asset were recorded as the New York Department of Public Service has provided the opportunity of rate recovery by New York State utilities of such additional taxes. All of these items are included in the “Other” category of the Utility Operating Revenue table above. As part of its 1998 two year rate settlement approved by the NYPSC, Distribution Corporation was allowed to utilize certain refunds from upstream pipeline companies and certain other credits (referred to as the “refund pool”) to offset certain specific expense items. When dollars from the refund pool are utilized, revenue is recorded and an equal amount of operation and maintenance (O&M) expense is also recorded (thus there is no earnings impact). The amount of refund pool revenue, and related O&M expense, recog- nized in 2000 was $9.7 million less than in 1999. 1999 Compared with 1998 Operating revenues for the Utility segment decreased $63.8 million in 1999 compared with 1998. This resulted from a reduction in retail and off-system gas sales revenue of $56.1 million and $15.3 million, respectively, and a reduction in other operating revenue of $7.2 million. These decreases were partly offset by an increase in transportation revenue of $14.8 million. 33 The recovery of lower gas costs and the general base rate decrease in the New York jurisdiction effective October 1, 1998, caused the decrease in retail gas revenue. The recovery of lower gas costs resulted from both lower retail volumes sold of 3.2 Bcf and a lower average cost of purchased gas (see discussion of pur- chased gas below under the heading “Purchased Gas”). Despite weather that was colder than 1998, retail volumes sold decreased, mainly due to the migration of residential and small commercial retail customers to transportation service. Transportation revenue increased and volumes are up 3.9 Bcf as a result of the migra- tion and because of colder weather. Off-system revenue is down due to lower volumes sold of 3.7 Bcf. The decrease in other operating revenue of $7.2 million is due primarily to a $7.2 million gas restruc- turing reserve, as discussed above, reducing revenue in 1999, $6.0 million of revenue recorded in 1998 as a result of IRS audits and $0.4 million of a revenue reduction in 1999 due to a final IRS audit settlement. These items were offset in part by a $7.1 million lower refund provision recorded in 1999 as compared with the 1998 refund provision. The revenue related to the IRS audits represents the rate recovery of interest expense as allowed by the New York rate settlement of 1996. The refund provision represents the 50% sharing with customers of earnings over a predetermined amount in accordance with the New York rate set- tlements of 1996 and 1998. All of these items are included in the “Other” category of the Utility Operating Revenue table above. 2000 Compared with 1999 In the Utility segment, 2000 earnings were $57.7 million, up $0.8 million from the prior year. The increase in earnings resulted primarily from two items in the prior year (expenses related to an early retirement offer of $3.7 million (after tax) and a special reserve for gas restructuring of $4.7 million (after tax) which did not recur in the current year). These items were offset by higher stock appreciation rights (SARs) expense of $2.9 million (after tax), as discussed below, and revenue adjustments of $5.5 million (after tax), as discussed in the revenue section above. The increase in the market price of the Company’s common stock, while benefiting shareholders, carried with it the required recognition of expense for SARs. This expense is spread across all segments, with the greatest impact on Pipeline and Storage, Utility and Exploration and Production segments. For 2000, total expense related to SARs for all segments was $9.2 million (after tax), and reflects the stock price increase from September 30, 1999 ($47.19 per common share) to September 30, 2000 ($56.06 per common share). The impact of weather on Distribution Corporation’s New York rate jurisdiction is tempered by a weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. In addi- tion, in periods of colder than normal weather, the WNC benefits Distribution Corporation’s New York customers. In 2000, the WNC in New York preserved earnings of approximately $8.1 million (after tax) as weather, overall in the New York service territory, was warmer than normal for the period from October 1999 through May 2000. Since the Pennsylvania rate jurisdiction does not have a WNC, uncontrollable weather variations directly impact earnings. In the Pennsylvania service territory, since 2000 weather was only 0.9% colder than 1999, no significant earnings variances occurred. NATIONAL FUEL GAS COMPANY Earnings 34 NATIONAL FUEL GAS COMPANY 1999 Compared with 1998 In the Utility segment, 1999 earnings were $56.9 million, up $5.1 million from the prior year. This was largely because the settlement of the primary issues of IRS audits of years 1977-1994 had a negative impact on earnings in 1998. In addition, adjustments made relating to the final settlement of these audits had a positive impact to earnings in 1999. Absent the IRS audit items, earnings of the Utility segment were up $0.6 million from the prior year. Lower O&M and interest expenses, a lower refund provision in 1999 (as noted in the revenue discus- sion above), positive adjustments for lost and unaccounted-for gas related to 1998 and 1999 and slightly colder weather (which mainly benefits the Pennsylvania jurisdiction), were the positive contributors to earn- ings in 1999. These items offset the costs associated with the 1999 early retirement offers, as well as the effects of a rate settlement that included a $7.2 million rate reduction in New York that became effective October 1, 1998 and the previously discussed special gas restructuring reserve. In 1999, the WNC in New York preserved earnings of approximately $6.3 million (after tax) as weather, overall in the New York service territory, was warmer than normal for the period from October 1998 through May 1999. In the Pennsylvania service territory, weather that was 4.0% colder than 1998 increased earnings by approximately $0.5 million (after tax). DEGREE DAYS Year Ended September 30 2000: 1999: 1998: Buffalo Erie Buffalo Erie Buffalo Erie Normal 6,932 6,230 6,848 6,223 6,689 6,223 Actual 6,312 5,657 6,179 5,607 5,914 5,389 Percent (Warmer) Colder Than Normal Prior Year (8.9%) (9.2%) (9.8%) (9.9%) (11.6%) (13.4%) 2.1% 0.9% 4.5% 4.0% (12.9%) (15.7%) Purchased Gas The cost of purchased gas is currently the Company’s single largest operating expense. Annual variations in purchased gas costs can be attributed directly to changes in gas sales volumes, the price of gas purchased and the operation of purchased gas adjustment clauses. Currently, Distribution Corporation has contracted for long-term firm transportation capacity with Supply Corporation and six other upstream pipeline companies, for long-term gas supplies with a combina- tion of producers and marketers and for storage service with Supply Corporation and three nonaffiliated companies. In addition, Distribution Corporation can satisfy a portion of its gas requirements through spot market purchases. Changes in wellhead prices have a direct impact on the cost of purchased gas. Distribution Corporation’s average cost of purchased gas, including the cost of transportation and storage, was $4.93 per thousand cubic feet (Mcf) in 2000, an increase of 29% from the average cost of $3.82 per Mcf in 1999. The average cost of purchased gas in 1999 was 7.5% lower than the $4.13 per Mcf in 1998. 35 NATIONAL FUEL GAS COMPANY Pipeline and Storage Revenues PIPELINE AND STORAGE OPERATING REVENUES Year Ended September 30 (Thousands) Firm Transportation Interruptible Transportation Firm Storage Service Interruptible Storage Service Other PIPELINE AND STORAGE THROUGHPUT – (MMCF) Year Ended September 30 Firm Transportation Interruptible Transportation 2000 1999 1998 $92,305 1,578 93,883 62,899 287 63,186 12,590 $91,279 856 92,135 63,655 173 63,828 12,820 $93,362 985 94,347 62,850 655 63,505 13,131 $169,659 $168,783 $170,983 2000 1999 1998 291,818 21,730 313,548 300,242 8,061 308,303 298,738 14,310 313,048 2000 Compared with 1999 Operating revenues increased $0.9 million in 2000 compared with 1999. The increase resulted primarily from higher firm transportation revenue of $1.0 million, higher interruptible transportation and interrupt- ible storage service revenues of $0.8 million, offset by lower firm storage service revenue of $0.8 million. The increase in firm transportation revenues resulted primarily from a $1.3 million “pass-through” type item (which did not recur in 2000) that reduced revenues in the prior year and correspondingly reduced O&M expense in the prior year, thus having no earnings impact. The increase in interruptible transportation and interruptible storage service revenues is principally the result of higher throughput volumes. The decrease in firm storage service revenue was the result of discounted storage service rates, as well as the loss of certain storage service customers. However, for the 2001 winter heating season, all firm storage capacity has been subscribed. Transportation volumes in this segment increased 5.2 Bcf. Generally, volume fluctuations do not have a significant impact on revenues as a result of Supply Corporation’s straight fixed-variable (SFV) rate design. However, as mentioned above, the higher interruptible volumes did add to revenues in 2000. 1999 Compared with 1998 Operating revenues decreased $2.2 million in 1999 compared with 1998. The decrease resulted primarily from lower firm transportation revenue of $2.1 million, lower interruptible transportation and interruptible storage service revenue of $0.6 million, offset in part by higher firm storage service revenue of $0.8 million. 36 NATIONAL FUEL GAS COMPANY Earnings Approximately $1.0 million of the decrease in the firm transportation revenue related to a “pass-through” type item (mentioned above) that correspondingly reduced O&M expense, thus having no bottom line earn- ings impact. Interruptible transportation and interruptible storage service revenue decreased (and interrupt- ible volumes transported decreased 6.2 Bcf) as a result of full storages at the beginning of the 1998-99 heating season and a warmer than normal winter in 1998-99; thus Supply Corporation lacked available storage space to service interruptible customers. Lower interruptible storage service generally results in lower interruptible transportation. Transportation volumes in this segment decreased 4.7 Bcf. Generally, volume fluctuations do not have a significant impact on revenues as a result of Supply Corporation’s SFV rate design. However, as mentioned above, lower interruptible transportation volumes did negatively impact revenue for 1999. 2000 Compared with 1999 Earnings in the Pipeline and Storage segment decreased $8.2 million in 2000 compared with 1999. In the current year increased SARs expense of $4.6 million (after tax) and the addition of $1.1 million of New York State income tax, resulting from recently enacted tax law changes in New York State, contributed to the decrease in earnings. The Federal Energy Regulatory Commission (FERC), which regulates this segment, has not provided for the recovery of additional taxes as has the New York Department of Public Service. Several items in the prior year, which did not recur in the current year, also contributed to 2000 earnings being less than 1999 earnings. The prior year’s earnings included interest income of $1.2 million (after tax) and a reduction in income tax of $1.7 million related to the final settlement of IRS audits of years 1977-1994. In addition, 1999 included the recovery of $0.5 million (after tax) of costs related to a gathering project that had been previously reserved for and the recovery, through insurance, of $0.4 million (after tax) of a previ- ously expensed base gas loss. These items were offset in part by a charge in 1999 for an early retirement of $0.9 million (after tax). 1999 Compared with 1998 Earnings in the Pipeline and Storage segment remained at $39.8 million for 1999 and 1998. Lower revenues, as discussed above, and nonrecurring income in 1998 from a buyout of a firm transportation agreement by a customer in the amount of $1.6 million (after tax), were offset by lower O&M and interest expenses in 1999. Items causing lower O&M expense in 1999 when compared to 1998 include the estab- lishment of reserves in 1998 for preliminary survey and investigation costs associated with a proposed incre- mental expansion project and a natural gas gathering project (mainly due to lack of interest in furthering these projects). In addition, Supply Corporation recognized a base gas loss at its Zoar Storage Field in 1998. In total, these three items amounted to $2.4 million of after tax expense in 1998. In 1999, Supply Corporation reversed $0.5 million (after tax) of the gathering project reserve, and recovered, through insur- ance, $0.4 million (after tax) related to the Zoar base gas loss. Several significant items also increased O&M expense in 1999 when compared to 1998, including $0.9 million of after tax charges for early retirement offers in 1999 and the 1998 reversal of a portion of a reserve set up in a prior period for a storage project. Supply Corporation was able to recover approximately $0.7 million (after tax) by selling preliminary engi- neering, survey, environmental and archeological information from this storage project to the Independence Pipeline Company. 37 NATIONAL FUEL GAS COMPANY Exploration and Production Revenues EXPLORATION AND PRODUCTION OPERATING REVENUES Year Ended September 30 (Thousands) 2000 1999 1998 Gas (after Hedging) Oil (after Hedging) Gas Processing Plant Other PRODUCTION VOLUMES Year Ended September 30 Gas Production (million cubic feet) Gulf Coast West Coast Appalachia Canada Oil Production (thousands of barrels) Gulf Coast West Coast Appalachia Canada AVERAGE PRICES Year Ended September 30 Average Gas Price/Mcf Gulf Coast West Coast Appalachia Canada Weighted Average Weighted Average After Hedging(1) Average Oil Price/bbl Gulf Coast West Coast(2) Appalachia Canada Weighted Average Weighted Average After Hedging(1) $108,832 117,606 17,666 (6,034) $238,070 $ 83,229 52,050 11,751 (36) $146,994 $ 82,910 34,069 4,937 2,356 $124,272 2000 1999 1998 32,760 4,374 4,344 192 41,670 1,415 2,824 9 899 5,147 28,758 3,977 4,431 — 37,166 1,373 2,633 10 — 4,016 29,461 2,146 4,867 — 36,474 1,228 1,376 10 — 2,614 2000 1999 1998 $3.29 $3.62 $3.16 $2.52 $3.31 $2.61 $28.27 $23.87 $25.12 $29.28 $26.03 $22.85 $2.15 $2.28 $2.44 — $2.20 $2.24 $15.18 $11.62 $14.73 — $12.85 $12.96 $2.40 $2.14 $2.88 — $2.45 $2.27 $14.69 $ 9.85 $16.80 — $12.15 $13.03 (1) Refer to further discussion of hedging activities below under “Market Risk Sensitive Instruments” and in Note F – Financial Instruments in Item 8 of this report. (2) Includes low gravity oil which generally sells for a lower price. 38 NATIONAL FUEL GAS COMPANY Earnings 2000 Compared with 1999 Operating revenues increased $91.1 million in 2000 compared with 1999. Oil production revenues, net of hedging activities, increased $65.6 million as the weighted average price of oil after hedging increased 76% and production increased 28%, from the prior year. Oil production from Canadian wells acquired as part of the June 2000 acquisition of Tri Link Resources, Ltd. (Tri Link) now known as National Fuel Exploration Corp. (NFE), added $26.3 million to oil revenues. Gas production revenues, net of hedging activities, increased $25.6 million as production increased 12% and the weighted average price of gas after hedging increased 17%. Revenue from Seneca’s gas processing plant was up $5.9 million. These items were partly offset by a $6.0 million decrease in other revenues resulting primarily from mark-to-market and other revenue adjustments related to written options. Refer to further discussion of these and other derivative financial instruments in the “Market Risk Sensitive Instruments” section that follows and in Note F – Financial Instruments in Item 8 of this report. 1999 Compared with 1998 Operating revenues increased $22.7 million in 1999 compared with 1998. Oil production revenues, net of hedging activities, increased $18.0 million as production increased 54% (mainly the result of West Coast production from the properties acquired in 1998). Gas production revenue, net of hedging activities, increased $0.3 million due to higher production (also mainly the result of West Coast production from the properties acquired in 1998). Revenue from Seneca’s gas processing plant was up $6.8 million. These items were partly offset by a negative mark-to-market revenue adjustment of $1.3 million related to written options. 2000 Compared with 1999 In the Exploration and Production segment, 2000 earnings of $34.9 million were up $27.8 million when compared with 1999. NFE added $6.4 million to 2000 earnings. As discussed above, significant improve- ment in oil and gas pricing, combined with an increase in production, were the main reasons for higher earnings. Partly offsetting higher revenues was an increase in production related expenses, including higher depletion, an increase in lease operating costs, and higher production taxes. In addition, general and admin- istrative expenses were up as a result of higher costs associated with labor and benefits (including SARs expense), and interest expense increased due to higher borrowings related to the acquisition of Tri Link. The increase in the gas processing plant revenue of $5.9 million was offset by an equal amount of related expense increase. 1999 Compared with 1998 In the Exploration and Production segment, 1999 earnings of $7.1 million were down $7.9 million (exclu- sive of the two non-cash special items in 1998) when compared with 1998. This is largely because the settle- ment of the primary issues of IRS audits of years 1977-1994 had a positive impact on earnings in 1998. Absent the IRS audit items, earnings of the Exploration and Production segment were down $1.4 million from 1998. Depressed oil and gas prices for much of 1999 were the main reason for these lower earnings. Higher oil and gas production revenue, as noted in the revenue section above, was offset by increases in lease operating, depletion and interest expense related mainly to Seneca’s acquisition activity in 1998. The increase in the gas processing plant revenue of $6.8 million was largely offset by an increase in related expenses of $6.2 million. 39 NATIONAL FUEL GAS COMPANY International Revenues INTERNATIONAL OPERATING REVENUES Year Ended September 30 (Thousands) 2000 1999 1998 Heating Electricity Other INTERNATIONAL HEATING AND ELECTRIC VOLUMES Year Ended September 30 Heating Sales (Gigajoules)(1) Electricity Sales (megawatt hours) (1) Gigajoules = one billion joules. A joule is a unit of energy. $69,387 31,426 3,923 $71,974 34,158 913 $104,736 $107,045 $49,560 22,774 3,925 $76,259 2000 1999 1998 10,222,024 1,147,303 10,047,042 1,138,980 7,116,776 763,848 2000 Compared with 1999 Operating revenues decreased $2.3 million in 2000 compared with 1999. The decrease in revenues is largely due to the decrease in value of the Czech koruna (CZK) as compared to the U.S. dollar. While higher heating and electricity sales contributed to higher operating revenues (in CZK), the decrease in value of the CZK caused an overall decrease in revenues when translated into U.S. dollars. 1999 Compared with 1998 Operating revenues increased $30.8 million in 1999 compared with 1998. The increase in revenues as well as the increase in heat and electric volumes, as shown in the tables above, reflects the fact that 1999 was the first year in which a full twelve months of sales and revenues are included for PSZT (now part of the com- bined company known as UE). Sales and revenues for 1998 include only eight months of activity as PSZT was acquired in February 1998. 2000 Compared with 1999 The International segment’s 2000 earnings were $3.3 million, or $1.0 million higher than 1999 earnings. This increase can be attributed to lower O&M expense, an income tax adjustment that benefited earnings in 2000, and additional consideration received in 2000 on the sale of a previously written-off project. These were partly offset by a decrease in margin and the negative impact of the decline in the exchange rate, as dis- cussed above. 1999 Compared with 1998 The International segment’s 1999 earnings were $2.3 million, or $1.0 million higher than 1998 earnings. Earnings for 1999 reflect a full twelve months of results from PSZT, while 1998 only included eight months of earnings. The contribution from these additional months in 1999 was offset in part by higher interest expense during 1999. In addition, 1998 earnings included a $2.7 million (after tax) net gain associated with U.S. dollar denominated debt, which did not recur in 1999. This debt was converted to a Czech koruna denominated loan in December 1998. Earnings 40 NATIONAL FUEL GAS COMPANY Energy Marketing Revenues ENERGY MARKETING OPERATING REVENUE Year Ended September 30 (Thousands) Natural Gas (after Hedging) Electricity Other ENERGY MARKETING VOLUMES Year Ended September 30 Natural Gas – (MMcf) 2000 1999 1998 $139,614 1,941 (7,626) $133,929 $97,514 1,551 23 $99,088 $86,877 253 57 $87,187 2000 35,465 1999 34,454 1998 26,453 2000 Compared with 1999 Operating revenues increased $34.8 million in 2000 compared with 1999. The primary reason for this increase is the higher gas costs that are reflected in the natural gas marketing revenues. In addition, higher marketing volumes reflect an increase in NFR customers from 17,480 at September 30, 1999 to 33,115 at September 30, 2000. Almost 89% of the increase in customers were residential customers. These higher rev- enues were offset in part by a negative $8.6 million mark-to-market adjustment related to certain derivative financial instruments (included in “Other” on the table above). See further discussion of NFR’s use of deriv- atives in the “Market Risk Sensitive Instruments” section that follows and in Note F – Financial Instruments in Item 8 of this report. 1999 Compared with 1998 Operating revenues increased $11.9 million in 1999 compared with 1998. This increase reflected higher marketing volumes as NFR customers increased from 5,476 at September 30, 1998 to 17,480 at September 30, 1999. Over 75% of the increase in customers were residential customers. Earnings 2000 Compared with 1999 The Energy Marketing segment incurred a loss for 2000 of $7.8 million, a decrease of approximately $9.9 million over 1999 earnings of $2.1 million. The most significant reasons for the decrease were mark-to- market losses related to certain derivative financial instruments of $5.6 million (after tax), the accrual of a $1.6 million (after tax) loss contingency on the unhedged portion of this segment’s fixed price sales contracts for sale of natural gas to customers in 2001, and higher expenses including interest. 1999 Compared with 1998 The Energy Marketing segment’s 1999 earnings were $2.1 million, an increase of $1.3 million over 1998 earnings. Volumes of natural gas marketed increased 30% to 34.5 Bcf in 1999 from 26.5 Bcf in 1998 and margins were also up from 1998. These positive contributions to earnings were partly offset by higher expenses for labor, office expense and advertising. 41 NATIONAL FUEL GAS COMPANY Timber Revenues TIMBER OPERATING REVENUES Year Ended September 30 (Thousands) 2000 1999 Log Sales Green Lumber Sales Kiln Dry Lumber Sales Other TIMBER BOARD FEET Year Ended September 30 (Thousands) Log Sales Green Lumber Sales Kiln Dry Lumber Sales $24,091 4,397 10,152 532 $39,172 2000 9,370 8,193 6,987 $18,276 4,018 8,197 626 $31,117 1999 6,902 8,541 5,711 1998 $9,157 4,119 3,991 538 $17,805 1998 2,794 7,634 2,710 24,550 21,154 13,138 2000 Compared with 1999 Operating revenues for the Timber segment increased $8.1 million. This increase was primarily the result of higher log sales and kiln dry lumber sales. Log sales are up due mainly to higher board feet of cherry veneer and export logs sold and higher average prices. The increase in kiln dry lumber sales is due to the operating of additional kilns brought on line in 1999 that were operational for a full 12 months in 2000 and the addi- tion of two more kilns brought on line in August 2000. 1999 Compared with 1998 Operating revenues for the Timber segment increased $13.3 million. This increase was primarily the result of higher log sales and kiln dry lumber sales. Revenue growth reflects the increased investment by this segment in timber and sawmills. Earnings 2000 Compared with 1999 Timber segment earnings of $6.1 million in 2000 were up $1.4 million when compared with 1999. The increase was due to higher operating revenues, as mentioned above, and an after tax gain on the sale of land and standing timber of $1.5 million. These items were partly offset by higher interest expense resulting from higher debt related to the PennzEnergy Company acquisition in July 1999 and by higher operating expenses. 1999 Compared with 1998 Timber segment earnings of $4.8 million in 1999 were up $2.9 million when compared with 1998. As noted above, timber revenues increased by 75% in 1999. These higher revenues were partly offset by higher O&M and interest expenses. Earnings growth reflects the increased investment by this segment in timber and sawmills. 42 NATIONAL FUEL GAS COMPANY Other Income and Interest Charges Although most of the variances in Other Income items and Interest Charges are discussed in the earnings discussion by segment above, following is a summary on a consolidated basis: Other Income Other income decreased $1.9 million in 2000 compared with 1999. This decrease resulted from $3.2 million of interest income related to the final settlement of IRS audits for years 1977-1994 which was recorded during 1999, as well as a $2.4 million gain recorded in 1999 which resulted from the demutualization of an insurance company. As a policyholder, the Company received stock of the insurance company as part of its initial public offering. Neither of these items recurred in 2000. Partly offsetting this decrease was a $2.6 million gain on the sale of land and standing timber in 2000, as well as $0.5 million of additional considera- tion received in 2000 on the sale of a previously written-off project in the International segment. Other income decreased $23.5 million in 1999 compared with 1998. This decrease was primarily due to a decrease in interest income related to the settlement of IRS audits. In 1999 and 1998, $3.1 million and $18.5 million, respectively, of interest income was recognized related to these audits. Lower other income in 1999 also reflects two items recorded in 1998: a net gain of $5.1 million associated with U.S. dollar denomi- nated debt in the International segment and a buyout of a firm transportation agreement by a Pipeline and Storage segment customer in the amount of $2.5 million. Partly offsetting these items was a $2.4 million gain recorded in 1999 resulting from the demutualization of an insurance company. Interest Charges Interest on long-term debt increased $1.8 million in 2000 and $12.2 million in 1999. The increase in both years can be attributed mainly to a higher average amount of long-term debt outstanding. Long-term debt balances have grown significantly over the past several years primarily as a result of acquisition activity in the Exploration and Production and International segments. Other interest charges increased $10.6 million in 2000 and decreased $9.8 million in 1999. The increase in 2000 was primarily the result of higher weighted average interest rates and higher average amounts of short-term debt outstanding. As discussed in “Financing Cash Flow” below, the acquisition of Tri Link was financed with short-term debt. The decrease in 1999 compared to 1998 resulted primarily from $11.7 million of interest expense recorded in 1998 related to the settlement of IRS audits. Partly offsetting this decrease in 1999, interest on short-term debt increased mainly as a result of higher average amounts of debt outstanding. Outlook for 2001* This outlook for 2001 section contains forward-looking statements, all of which are based on current expec- tations. There is no assurance that the Company’s projections will in fact be achieved and these projections do not reflect any acquisitions or divestitures which may occur in 2001. Reference should be made to the various important factors listed under the heading “Safe Harbor for Forward-Looking Statements” that could cause actual future results to differ materially. The Company expects that earnings for 2001 will fall within the range of $168 million to $172 million, or $4.25 per basic common share to $4.35 per basic common share.* Higher earnings in the Exploration and Production segment is the main driver of the expected increase in earnings for 2001 as com- pared with actual earnings for 2000.* Production estimates for 2001 are in the range of 95 to 100 Bcfe (with oil representing 54% of that production).* Spot price assumptions for 2001 are $3.98 per Mcf for natural gas and $25.51 per bbl for crude oil.* Information on the Exploration and Production segment’s hedging program is provided in the “Market Risk Sensitive Instruments” section that follows. 43 NATIONAL FUEL GAS COMPANY 44 In the Utility segment, earnings are expected to be down in 2001 as compared with 2000.* The overall rate of return (operating income after income tax) is expected to be about 9% on an average rate base for 2001 of $623 million for the New York jurisdiction and about 9.5% on an average rate base for 2001 of $242 million in the Pennsylvania jurisdiction.* These figures compare to 2000’s actual return on rate base of 10.1% in New York and 9.9% in Pennsylvania. The expected decrease in New York reflects the recent rate settlement with the NYPSC whereby rates in the New York jurisdiction are reduced by $10 million for 2001. In addition, the rate settlement reduced the targeted return on equity, above which earnings are shared 50% with rate payers, from 12% to 11.5%. In the Pipeline and Storage segment, 2001 earnings are expected to increase as the overall rate of return on rate base should increase from 10.6% in 2000 to about 12 to 12.5% in 2001 on an average rate base in 2001 of $407 million.* Anticipated O&M savings is a significant reason for this increase.* In the International segment, earnings for 2001 are anticipated to be close to 2000 earnings after a reduction for the non-recurring income tax adjustment of $1.8 million that is included in 2000 earnings.* In the Energy Marketing segment, 2001 earnings are expected to be at break even or a slight loss.* In the Timber segment, earnings for 2001 should be flat to slightly up as compared with 2000 earnings.* Earnings for all other, including Corporate, are expected to be flat to down slightly as compared with 2000 earnings.* Capital Resources and Liquidity The primary sources and uses of cash during the last three years are summarized in the following condensed statement of cash flows: SOURCES (USES) OF CASH Year Ended September 30 (Millions) Provided by Operating Activities Capital Expenditures Investment in Subsidiaries, Net of Cash Acquired Investment in Partnerships Other Investing Activities Short-Term Debt, Net Change Long-Term Debt, Net Change Issuance of Common Stock Dividends Paid on Common Stock Dividends Paid to Minority Interest Effect of Exchange Rates on Cash Net Increase (Decrease) in Cash and Temporary Cash Investments Operating Cash Flow 2000 1999 1998 $238.2 (269.4) (123.8) (4.4) 13.3 226.5 (18.1) 14.3 (73.0) (0.2) (0.5) $267.5 (256.1) (5.8) (3.6) 6.7 67.2 (15.6) 10.7 (69.9) (0.2) (2.1) $249.9 (390.1) (112.0) (5.5) 7.6 229.4 94.9 7.9 (67.0) (0.3) 1.6 $2.9 $(1.2) $16.4 Internally generated cash from operating activities consists of net income available for common stock, adjusted for noncash expenses, noncash income and changes in operating assets and liabilities. Noncash items include depreciation, depletion and amortization, deferred income taxes, minority interest in foreign subsidiaries, the cumulative effect of a change in accounting for depletion (1998) and the impairment of oil and gas producing properties (1998). NATIONAL FUEL GAS COMPANY Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary sub- stantially from year to year because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs and weather also significantly impact cash flow. The impact of weather on cash flow is tempered in the Utility segment’s New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by Supply Corporation’s SFV rate design. Net cash provided by operating activities totaled $238.2 million in 2000, a decrease of $29.3 million compared with the $267.5 million provided by operating activities in 1999. The decrease is attributable primarily to higher gas costs in the Utility and Energy Marketing segments stemming from rising natural gas prices. In the Utility segment, any unrecovered gas costs are deferred for future recovery. Partially offsetting this negative impact to cash provided by operating activities, the Exploration and Production segment expe- rienced an increase in cash provided by operating activities. Higher cash receipts from the sale of oil and gas production resulted from higher production and significantly higher prices. Investing Cash Flow Expenditures for Long-Lived Assets Expenditures for long-lived assets include additions to property, plant and equipment (capital expenditures) and investments in corporations (stock acquisitions) or partnerships, net of any cash acquired. The Company’s expenditures for long-lived assets totaled $398.8 million in 2000. The table below presents these expenditures by business segment: Year Ended September 30, 2000 (Millions) Utility Pipeline and Storage Exploration and Production International Energy Marketing Timber All Other Capital Expenditures Investments in Corporations or Partnerships $ 55.8 34.0(1) 156.2 9.8 0.1 13.6 1.1 $270.6(1) $ — 1.8 123.8 — — — 2.6 $128.2 Total Expenditures For Long- Lived Assets $ 55.8 35.8 280.0 9.8 0.1 13.6 3.7 $398.8 (1) Includes non-cash acquisition of $1.2 million in a stock-for-asset swap. Utility The majority of the Utility capital expenditures were made for replacement of mains and main extensions, as well as for the replacement of service lines. Pipeline and Storage The majority of the Pipeline and Storage capital expenditures were made for additions, improvements, and replacements to this segment’s transmission and storage systems. Of the total capital expenditures, $9.2 million was related to the acquisition of another company’s interest in the Niagara Spur Loop Line and the Ellisburg-Leidy pipeline in January 2000. This acquisition was financed with short-term borrowings. The capital expenditures also include approximately $1.2 million for natural gas wells and related pipelines as well as some undeveloped timber property acquired from Cunningham Natural Gas Corporation (Cunningham) in November 1999. These assets were acquired through the issuance of 54,674 shares of the 45 NATIONAL FUEL GAS COMPANY 46 Company’s common stock. In addition to the assets identified above, the Company received Cunningham’s temporary cash investments in exchange for the shares of Company common stock. During 2000, SIP made a $1.8 million investment in Independence Pipeline Company, a Delaware general partnership (Independence), and had an aggregate investment balance of $13.7 million at September 30, 2000. This investment represents a one-third partnership interest. The investment has been financed with short-term borrowings. Independence intends to build a 400-mile natural gas pipeline (the Independence Pipeline) from Defiance, Ohio to Leidy, Pennsylvania at an estimated cost of $680 million.* If construction never begins on the Independence Pipeline project, the Company’s share of the development costs (including SIP’s investment in Independence) is estimated not to exceed $15.0 million.* On July 12, 2000, the FERC issued a Certificate of Public Convenience and Necessity (the Certificate) authorizing, among other things, the construction and operation of the Independence Pipeline, subject to satisfaction of various conditions spelled out in the Certificate and in previous FERC orders. Among those conditions is the requirement that, before construction may commence, Independence must file at FERC executed, firm transportation agreements with “no out” clauses for at least 68.2% of its capacity. (Independence already filed, on June 26 and July 6, 2000, precedent agreements for firm transportation amounting to about 38% of the capacity of the Independence Pipeline, thereby satisfying a FERC require- ment previously imposed as a precondition to FERC’s issuance of the Certificate.) The Independence Pipeline partners are working on obtaining the required customer commitments. The Certificate also requires that the Independence Pipeline be constructed and placed in service by July 12, 2003. Assuming contracts are in place in quantities satisfactory to the partners, the Independence Pipeline’s planned in service date is November 1, 2002.* The Certificate also includes an environmental condition that Independence file an “implementation plan” within 60 days after Independence accepted the Certificate. In October and November 2000, Independence timely filed a preliminary implementation plan which included a request for an extension of time to provide certain technical information, in order to allow the remaining field surveys (for example, for endangered species) to be commenced in spring 2001. This timing would be consistent with Independence’s planned in service date of November 1, 2002, and the Certificate’s deadline of July 12, 2003 to complete construction. On November 20, 2000, a FERC official issued a letter requiring Independence to file a full implementation plan, including the necessary technical information, by May 1, 2001, and warning that if Independence cannot comply with these terms, its Certificate authority could be in jeopardy. This letter also requires Independence to file monthly status reports on environmental permitting and land acquisition activ- ities. It is possible that Independence will be unable to file timely an implementation plan which meets the requirements set out in the November 20 letter, and that Independence’s application could be dismissed.* Exploration and Production The Exploration and Production segment capital expenditures included approximately $113.6 million for the Company’s offshore program in the Gulf of Mexico, including offshore drilling expenditures, offshore construction, lease acquisition costs and geological and geophysical expenditures. The remaining $42.6 million of capital expenditures included onshore drilling, construction and recompletion costs for wells located in Louisiana, Texas, California and Canada as well as onshore geological and geophysical costs, including the purchase of certain 3-D seismic data and fixed asset purchases. In June 2000, the Company acquired the outstanding shares of Tri Link, a Calgary, Alberta based oil and gas exploration and production company. This acquisition built the Company’s total reserve base to approximately one trillion cubic feet equivalent.* The cost of acquiring the outstanding shares of Tri Link was approximately $123.8 million. The acquisition was financed with short-term borrowings. Refer to “Financing Cash Flow” for a discussion of the redemption of the debt that was assumed as part of the Tri Link acquisition. NATIONAL FUEL GAS COMPANY International The majority of the International segment capital expenditures were concentrated in the areas of improve- ments and replacements within the district heating and power generation plants in the Czech Republic. Energy Marketing The Energy Marketing capital expenditures consisted primarily of furniture, equipment and computer hard- ware and software. Timber The majority of the Timber segment’s capital expenditures consisted of the purchase of land and timber in Pennsylvania, and the construction or purchase of new facilities and equipment for this segment’s sawmill and kiln operations. All Other Expenditures for Long-Lived Assets for all other subsidiaries consisted of the purchase of a 50% interest in a gas processing facility and the purchase of a 50% partnership interest in Seneca Energy II, LLC which generates and sells electricity to a public utility by using methane gas obtained from a landfill owned by an outside party. Other Investing Activities Other cash provided by or used in investing activities primarily reflects cash received on the sale of invest- ments in property, plant and equipment. Estimated Capital Expenditures The Company’s estimated capital expenditures for the next three years are:* Year Ended September 30 (Millions) Utility Pipeline and Storage Exploration and Production International Timber 2001 $ 49.8 38.2 164.9 15.5 5.0 $273.4 2002 $ 48.1 26.6 180.8 2.5 5.0 $263.0 2003 $ 47.1 19.9 202.1 2.5 5.0 $276.6 Estimated capital expenditures for the Utility segment in 2001 will be concentrated in the areas of main and service line improvements and replacements and, to a minor extent, the installation of new services.* Estimated capital expenditures for the Pipeline and Storage segment in 2001 will be concentrated in the reconditioning of storage wells and the replacement of storage and transmission lines.* The estimated capital expenditures also include $5.0 million for an increase in horsepower at the Ellisburg, Pennsylvania compres- sor station.* In addition, $8.1 million has been budgeted for the construction of a transmission line from Lamont, Pennsylvania to Roystone, Pennsylvania.* Estimated capital expenditures in 2001 for the Exploration and Production segment include approxi- mately $105.4 million for the onshore program ($59.6 million in Canada).* Of this amount, approximately $59.9 million ($46.0 million in Canada) is intended to be spent on exploratory and development drilling.* The estimated expenditures also include approximately $59.5 million for the offshore program in the Gulf of Mexico.* Of this amount, approximately $49.9 million is intended to be spent on exploratory and develop- ment drilling.* 47 The estimated capital expenditures for the International segment in 2001 include approximately $13.0 million for the construction of a boiler at a district heating and power generation plant in the Czech Republic.* The new boiler will replace an existing boiler. Other capital expenditures will be concentrated on smaller improvements and replacements within the district heating and power generation plants.* Estimated capital expenditures in the Timber segment will be concentrated in the purchase of land and timber as well as the construction or purchase of new facilities and equipment for this segment’s sawmill and kiln operations.* The Company continuously evaluates capital expenditures and investments in corporations and partner- ships. The amounts are subject to modification for opportunities such as the acquisition of attractive oil and gas properties, timber or storage facilities and the expansion of transmission line capacities. While the major- ity of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s other business segments depends, to a large degree, upon market conditions.* Financing Cash Flow Consolidated short-term debt increased $226.5 million during 2000. The Company continues to consider short-term debt an important source of cash for temporarily financing capital expenditures and investments in corporations or partnerships, gas-in-storage inventory, unrecovered purchased gas costs, exploration and development expenditures and other working capital needs. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. In June 2000, the Company paid approximately $99.2 million to redeem the bank loans and convert- ible debentures of Tri Link. These redemptions were financed with short-term debt. In February 2000, the Company issued $150.0 million of 7.30% medium-term notes due in February 2003. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $149.3 million. The proceeds of this debt issuance were used to redeem $50.0 million of 6.60% medium-term notes which matured in February 2000 and to reduce short-term debt. The Company’s present liquidity position is believed to be adequate to satisfy known demands.* Under the Company’s existing indenture covenants, at September 30, 2000, the Company would have been permit- ted to issue up to a maximum of $487.0 million in additional long-term unsecured indebtedness at projected market interest rates. In addition, at September 30, 2000, the Company had regulatory authorizations and unused short-term credit lines that would have permitted it to borrow an additional $130.5 million of short- term debt. The Company’s embedded cost of long-term debt was 7.0% at both September 30, 2000 and 1999, respectively. In March 1998, the Company obtained authorization from the Securities and Exchange Commission (SEC), under the Holding Company Act, to issue long-term debt securities and equity securities in amounts not exceeding $2.0 billion at any one time outstanding during the order’s authorization period, which extends to December 31, 2002. In August 1999, the Company registered $625.0 million of debt and equity securities under the Securities Act of 1933. After the November 2000 medium-term note issuance discussed below, the Company currently has $275.0 million of debt and equity securities registered under the Securities Act of 1933. NATIONAL FUEL GAS COMPANY 48 NATIONAL FUEL GAS COMPANY In November 2000, the Company issued $200.0 million of 7.50% medium-term notes due in November 2010. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $197.3 million. The proceeds of this debt issuance were used to reduce short-term debt. The amounts and timing of the issuance and sale of debt or equity securities will depend on market conditions, regulatory authorizations, and the requirements of the Company. The Company is involved in litigation arising in the normal course of business. The Company is involved in regulatory matters arising in the normal course of business that involve rate base, cost of service and purchased gas cost issues, among other things. While the resolution of such litigation or regulatory matters could have a material effect on earnings and cash flows in the year of resolution, none of this litiga- tion, and none of these regulatory matters, are expected to change materially the Company’s present liquidity position, nor have a material adverse effect on the financial condition of the Company.* Market Risk Sensitive Instruments Energy Commodity Price Risk The Company, primarily in its Exploration and Production and Energy Marketing segments, uses various derivative financial instruments (derivatives), including price swap agreements, no cost collars, options and futures contracts, as part of the Company’s overall energy commodity price risk management strategy. Under this strategy, the Company manages a portion of the market risk associated with fluctuations in the price of natural gas and crude oil, thereby attempting to provide more stability to operating results. The Company has operating procedures in place that are administered by experienced management to monitor compliance with the Company’s risk management policies. The derivatives are not held for trading purposes. The fair value of these derivatives, as shown below, represents the amount that the Company would have to pay the respective counterparties at September 30, 2000 to terminate the derivatives. However, the tables below and the fair value that is disclosed do not consider the physical side of the natural gas and crude oil transactions that are related to the financial instruments. The Company may be exposed to credit risk on some of these derivatives. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check and then, on an ongoing basis, monitors counterparty credit exposure. The following tables disclose natural gas and crude oil price swap information by expected maturity dates for agreements in which the Company receives a fixed price in exchange for paying a variable price as quoted in “Inside FERC” or on the New York Mercantile Exchange. Notional amounts (quantities) are used to calculate the contractual payments to be exchanged under the contract. The weighted average variable prices represent the prices as of September 30, 2000. At September 30, 2000, the Company had not entered into any natural gas or crude oil price swap agreements extending beyond 2003. NATURAL GAS PRICE SWAP AGREEMENTS Notional Quantities (Equivalent Bcf) Weighted Average Fixed Rate (per Mcf) Weighted Average Variable Rate (per Mcf) Expected Maturity Dates 2001 17.9 $2.79 $4.79 2002 25.8 $3.75 $4.80 2003 1.2 $2.78 $4.76 Total 44.9 $3.34 $4.79 49 CRUDE OIL PRICE SWAP AGREEMENTS Expected Maturity Dates 2001 2002 2003 Total Notional Quantities (Equivalent bbls) Weighted Average Fixed Rate (per bbl) Weighted Average Variable Rate (per bbl) 3,717,915 $21.04 $33.87 4,840,980 $22.98 $33.87 1,803,000 $19.93 $33.87 10,361,895 $21.75 $33.87 At September 30, 2000, the Company would have had to pay the respective counterparties an aggregate of approximately $54.8 million to terminate the natural gas price swap agreements outstanding at that date. The Company would have had to pay an aggregate of approximately $51.4 million to the counterparties to terminate the crude oil price swap agreements outstanding at September 30, 2000. At September 30, 1999, the Company had natural gas price swap agreements covering 40.2 Bcf at a weighted average fixed rate of $2.69 per Mcf. The Company also had crude oil price swap agreements cover- ing 2,296,000 bbls at a weighted average fixed rate of $19.00 per bbl. As can be seen from the September 30, 2000 tables above, the Company has significantly increased its use of crude oil price swap agreements, which is primarily attributable to the increase in crude oil production that will be experienced as a result of the Tri Link acquisition in 2000. Tri Link (or NFE, as it is now known), primarily produces crude oil. The following tables disclose the notional quantities, the weighted average ceiling price and the weighted average floor price for the no cost collars used by the Company to manage natural gas and crude oil price risk. The no cost collars provide for the Company to receive monthly payments from (or make payments to) other parties when a variable price falls below an established floor price (the Company receives payment from the counterparty) or exceeds an established ceiling price (the Company pays the counter- party). At September 30, 2000, the Company had not entered into any natural gas or crude oil no cost collars extending beyond 2004. NO COST COLLARS Crude Oil Expected Maturity Dates 2001 2002 2003 2004 Total Notional Quantities (Equivalent bbls) Weighted Average Ceiling Price (per bbl) Weighted Average Floor Price (per bbl) 1,995,000 $30.07 $23.24 1,335,000 $28.26 $21.91 1,125,000 $26.41 $21.96 270,000 $25.80 $22.00 4,725,000 $28.44 $22.49 Natural Gas Notional Quantities (Equivalent Bcf) Weighted Average Ceiling Price (per Mcf) Weighted Average Floor Price (per Mcf) 6.6 $5.75 $3.83 — — — — — — — — — 6.6 $5.75 $3.83 At September 30, 2000, the Company would have had to pay the respective counterparties an aggregate of approximately $0.9 million to terminate the natural gas no cost collars outstanding at that date. The Company would have had to pay an aggregate of approximately $4.9 million to terminate the crude oil no cost collars outstanding at that date. At September 30, 1999, the Company did not have any no cost collars outstanding. During 2000, the Company began entering into no cost collars on the basis of obtaining better value for its crude oil and natural gas production than could be experienced through the use of price swap agreements only. The concentration of the no cost collars in crude oil is attributable to the crude oil production from NFE, as discussed above. NATIONAL FUEL GAS COMPANY 50 NATIONAL FUEL GAS COMPANY The following table discloses the net notional quantities, weighted average contract prices and weighted average settlement prices by expected maturity date for futures contracts used to manage natural gas price risk. At September 30, 2000, the Company held no futures contracts with maturity dates extending beyond 2002. FUTURES CONTRACTS Contract Volumes Purchased (Sold) (Equivalent Bcf) Weighted Average Contract Price (per Mcf) Weighted Average Settlement Price (per Mcf) (1) Volumes purchased amount to approximately 38,000 Mcf. Expected Maturity Dates 2001 (3.9) $4.23 $5.28 2002 —(1) $3.57 $4.77 Total (3.9) $4.20 $5.25 At September 30, 2000, the Company would have had to pay $5.5 million to terminate these futures contracts. At September 30, 1999, the Company had futures contracts covering 1.2 Bcf (net long position) at a weighted average contract price of $2.76 per Mcf. The following table discloses the notional quantities and weighted average strike prices by expected maturity dates for options used by the Company to manage natural gas and crude oil price risk. At September 30, 2000, the Company held no options with maturity dates extending beyond 2001. OPTIONS PURCHASED Natural Gas Notional Quantities (Equivalent Bcf) Weighted Average Strike Price (per Mcf) OPTIONS SOLD Natural Gas Notional Quantities (Equivalent Bcf) Weighted Average Strike Price (per Mcf) Crude Oil Notional Quantities (Equivalent bbls) Weighted Average Strike Price (per bbl) Expected Maturity Date - 2001 31.1 $4.76 Expected Maturity Date - 2001 37.9 $4.76 368,000 $15.25 At September 30, 2000, the Company would have had to pay $9.8 million to terminate these options. At September 30, 1999, the Company had purchased crude oil options outstanding covering 1,464,000 bbls at a weighted average strike price of $20.00 per bbl. The Company also had purchased natural gas options outstanding at September 30, 1999 covering 9.0 Bcf at a weighted average strike price of $2.72 per Mcf. The Company had sold crude oil options outstanding at September 30, 1999 covering 1,832,000 bbls at a weighted average strike price of $15.25 per bbl. The Company also had sold natural gas options out- standing at September 30, 1999 covering 31.0 Bcf at a weighted average strike price of $2.84 per Mcf. 51 Exchange Rate Risk The International segment’s investment in the Czech Republic is valued in Czech korunas, and, as such, this investment is subject to currency exchange risk when the Czech korunas are translated into U.S. dollars. The Exploration and Production segment’s investment in Canada is valued in Canadian dollars, and, as such, this investment is subject to currency exchange risk when the Canadian dollars are translated into U.S. dollars. During 2000, the Czech koruna decreased in value in relation to the U.S. dollar resulting in a $23.1 million negative adjustment to the Cumulative Foreign Currency Translation Adjustment (CTA) (a component of Accumulated Other Comprehensive Income). The Canadian dollar decreased in value in relation to the U.S. dollar resulting in a $4.3 million negative adjustment to the CTA. Further valuation changes to the Czech koruna and Canadian dollar would result in corresponding positive or negative adjustments to the CTA. Management cannot predict whether the Czech koruna or Canadian dollar will increase or decrease in value against the U.S. dollar.* Interest Rate Risk The Company’s exposure to interest rate risk primarily consists of short-term debt instruments. At September 30, 2000, these instruments included short-term bank loans and commercial paper totaling $601.2 million (domestically). The interest rate on these short-term bank loans and commercial paper approximated 6.7%. The Company’s short-term debt instruments also included $18.3 million of short-term bank loans in the Czech Republic at September 30, 2000. The interest rate on the Czech Republic loans approximated 5.7%. The following table presents the principal cash repayments and related weighted average interest rates by expected maturity date for the Company’s long-term fixed rate debt as well as the other debt of certain of the Company’s subsidiaries. The interest rates for the variable rate debt are based on those in effect at September 30, 2000: (Millions of Dollars) 2001 2002 2003 2004 2005 Thereafter Total Principal Amounts by Expected Maturity Dates National Fuel Gas Company Long-Term Fixed Rate Debt Weighted Average Interest Rate Paid Fair Value = $887.2 million Other Notes Long-Term Debt(1) Weighted Average Interest Rate Paid Fair Value = $40.9 million $ — —% $ — —% $150 7.3% $225 7.3% $ — —% $549 6.6% $924 6.9% $11.3 $8.5 $8.6 $8.7 $2.7 $1.1 $40.9 6.0% 5.9% 5.9% 5.9% 5.9% 6.0% 5.9% (1) $37.8 million is variable rate debt; $3.1 million is fixed rate debt. The Company utilizes an interest rate swap to eliminate interest rate fluctuations on its CZK 1,356,534,000 term loan ($33.7 million at September 30, 2000), which carries a variable interest rate of six month Prague Interbank Offered Rate (PRIBOR) plus 0.475%. Under the terms of the interest rate swap, which extends until 2002, the Company pays a fixed rate of 8.31% and receives a floating rate of six month PRIBOR. The Company would have paid approximately $1.4 million to settle the interest rate swap at September 30, 2000. NATIONAL FUEL GAS COMPANY 52 NATIONAL FUEL GAS COMPANY Utility Operation Rate Matters New York Jurisdiction On October 11, 2000, the NYPSC approved a settlement agreement (Agreement) between Distribution Corporation, Staff of the Department of Public Service, the New York State Consumer Protection Board and Multiple Intervenors (an advocate for large commercial and industrial customers) that establishes rates for a three-year period beginning October 1, 2000. The Agreement provides that customers will receive a bill credit of $17.6 million in the first year, of which $7.6 million relates to customers’ share of earnings accumu- lated under previous settlements. The credit will be reduced to $5.0 million in the second year, and in the third and subsequent years the credit will remain at $5.0 million unless the Company can demonstrate that it is no longer justified. Also, earnings beyond a target level of 11.5% return on equity will be shared equally between shareholders and ratepayers. The Agreement provides further that the Company and interested parties will resume discussions to address the NYPSC’s competition initiatives, including changes to “cus- tomer choice” transportation services, among other things. Those discussions are currently under way. On November 3, 1998, the NYPSC issued its Policy Statement Concerning the Future of the Natural Gas Industry in New York State and Order Terminating Capacity Assignment (Policy Statement). The Policy Statement sets forth the NYPSC’s “vision” on “how best to ensure a competitive market for natural gas in New York.” That vision includes the following goals: (1) Effective competition in the gas supply market for retail customers; (2) Downward pressure on customer gas prices; (3) Increased customer choice of gas suppliers and service options; (4) A provider of last resort (not necessarily the utility); (5) Continuation of reliable service and maintenance of operations procedures that treat all participants fairly; (6) Sufficient and accurate information for customers to use in making informed decisions; (7) The availability of information that permits adequate oversight of the market to ensure fair competition; and (8) Coordination of Federal and State policies affecting gas supply and distribution in New York State. The Policy Statement provides that the most effective way to establish a competitive market in gas supply is “for local distribution companies to cease selling gas.” The NYPSC indicated in its order that it hopes to accomplish that objective over a three-to-seven year transition period from the date the Policy Statement was issued, taking into account “statutory requirements” and the individual needs of each local distribution company (LDC).* The Policy Statement directs Staff to schedule “discussions” with each LDC on an “individualized plan that would effectuate our vision.” In preparation for negotiations, LDCs will be required to address issues such as a strategy to hold new capacity contracts to a minimum, a long-term rate plan with a goal of reducing or freezing rates, and a plan for further unbundling. In addition, Staff was instructed to hold collaborative sessions with multiple parties to discuss generic issues including reliability and market power regulation. Distribution Corporation has participated in the collaborative sessions. These collaborative sessions have not yet produced a consensus document on all issues before the NYPSC. Distribution Corporation will continue to participate in all future collaborative sessions.* On March 22, 2000, the NYPSC issued an order directing electric and gas utilities to file tariff amend- ments “to accommodate the wishes of retail access customers who prefer to receive combined, single bills from either their utility company or their [marketer]” (Billing Order). The tariff amendments will provide 53 NATIONAL FUEL GAS COMPANY 54 for marketer single-bill or utility single-bill services, thereby allowing a customer to choose a billing preference through the customer’s choice of suppliers – utility or marketer. Distribution Corporation has permitted marketer single billing since 1996. On November 1, 2000, Distribution Corporation filed tariff amendments in compliance with the Billing Order (and a subsequent order on rehearing of the Billing Order). Consistent with the provisions of the Billing Order, Distribution Corporation’s filing proposes to maintain its long-standing marketer single- bill model and add a permanent version of a utility-provided competitive single-bill service that has been available since May 2000. In addition, the filing proposes a credit (called a “backout credit”), available to marketers that issue single retail bills, equal to the long-run marginal cost of billing services avoided by Distribution Corporation. Based on the methodology set forth in the Billing Order, Distribution Corporation calculated a backout credit of $0.66 per bill avoided. The charge for Distribution Corporation’s competitive billing service was set at $0.71 (with a backout credit). The company’s filing proposed an effec- tive date of February 1, 2001 and is subject to review and approval by the NYPSC. At this time, Distribution Corporation is unable to ascertain the outcome of this proceeding.* On March 30, 2000, a collaborative was convened to address the NYPSC’s Order Instituting Proceeding in the so-called “Provider of Last Resort” (POLR) case. The collaborative was charged with the task of helping the NYPSC to “refine our concept of the mature competitive retail energy markets (especially the future role of the regulated utilities) and to identify and remove obstacles to its achievement.” The parties in this case are addressing, among other things, issues arising from utilities exiting the merchant function. The proceeding is also focusing on utilities’ responsibility to provide low-income assistance programs. Currently the parties are collaborating on a periodic basis and are in the process of identifying issues for further review. At this time, Distribution Corporation is unable to ascertain the outcome of the POLR proceeding.* On April 12, 2000, the NYPSC issued an order setting forth procedures for implementation of elec- tronic data interchange (EDI) for electronic exchange of retail access data in New York (EDI Order). As described by the NYPSC, EDI is the computer-to-computer exchange of routine business information in a standard form. The NYPSC believes that EDI is necessary to develop uniform data exchange protocol for the state’s customer choice initiatives. The EDI Order adopts provisions of a report prepared after an EDI collab- orative involving utilities, marketers and other interests. Distribution Corporation submitted its EDI imple- mentation plans on May 31, 2000. Implementation of EDI is expected to begin on a limited, test-only basis during the fourth quarter of calendar 2000. At this time, Distribution Corporation is unable to ascertain the outcome of the EDI proceeding.* The NYPSC continues to address, through various proceedings and “collaboratives,” upstream pipeline capacity issues arising from the restructuring. At this point, Distribution Corporation remains authorized to release upstream intermediate capacity to marketers serving former sales customers. Costs relating to retained upstream transmission capacity are recovered through a transition cost surcharge. At this time, Distribution Corporation does not foresee any material changes to upstream capacity requirements in the near term.* On May 15, 2000, the New York State tax law was amended to phase out the long-running tax on utility gross revenues beginning January 1, 2001. Offsetting the scheduled reductions, however, is the impo- sition of a net income based tax on the same utilities. In a report issued on October 13, 2000, the New York Department of Public Service recommended, among other things, that utilities be kept whole for any tax increases resulting from implementation of the changes. Toward that end, the report proposes that the mech- anism in rates currently used for recovery of the gross revenue tax be utilized to collect the new income tax. To the extent a utility’s income tax liability exceeds the amount collectible through the existing gross revenue tax recovery mechanism, deferral accounting would be authorized. The New York Department of Public NATIONAL FUEL GAS COMPANY Service’s report is subject to review and approval by the NYPSC after the close of the public comment period on December 18, 2000. Distribution Corporation plans to file tariff amendments revising its tax recovery mechanism consistent with the New York Department of Public Service’s recommendations. At this time, Distribution Corporation is unable to ascertain the outcome of this proceeding.* Pennsylvania Jurisdiction Distribution Corporation currently does not have a rate case on file with the Pennsylvania Public Utility Commission (PaPUC). Management will continue to monitor its financial position in the Pennsylvania jurisdiction to determine the necessity of filing a rate case in the future. A natural gas restructuring bill was signed into law on June 22, 1999. Entitled the Natural Gas Choice and Competition Act (Act), the new law requires all Pennsylvania LDCs to file tariffs designed to provide retail customers with direct access to competitive gas markets. Distribution Corporation submitted its com- pliance filing on October 1, 1999 for an effective date on or about July 1, 2000. The filing largely mirrored Distribution Corporation’s System Wide Energy Select program previously in effect, which substantially complied with the Act’s requirements. After negotiations with PaPUC Staff and intervenors, a settlement was reached with all parties except for the Pennsylvania Office of Consumer Advocate (OCA). The settlement parties generally agreed that Distribution Corporation’s proposal needed only modest changes to meet the requirements of the Act. Hearings were held and briefs filed on OCA’s open issues. In a Recommended Decision issued on March 31, 2000, the Administrative Law Judge rejected the OCA’s arguments and rec- ommended approval of the settlement agreement. On June 29, 2000, the PaPUC entered an Opinion and Order adopting the settlement, with immaterial changes. Distribution Corporation’s restructured rates and services became effective on July 1, 2000. Base rate adjustments in both the New York and Pennsylvania jurisdictions do not reflect the recovery of purchased gas costs. Such costs are recovered through operation of the purchased gas adjustment clauses of the appropriate regulatory authorities. 00000 Pipeline and Storage Supply Corporation currently does not have a rate case on file with the FERC. Management will continue to monitor Supply Corporation’s financial position to determine the necessity of filing a rate case in the future. Environmental Matters Other Matters It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. The Company has estimated its clean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be in the range of $6.4 million to $7.6 million.* The minimum liability of $6.4 million has been recorded on the Consolidated Balance Sheet at September 30, 2000. Other than discussed in Note H (referred to below), the Company is currently not aware of any material additional exposure to environmental liabilities. However, adverse changes in environmental regulations or other factors could impact the Company.* The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory poli- cies and procedures. For further discussion refer to Note H - Commitments and Contingencies under the heading “Environmental Matters” in Item 8 of this report. 55 NATIONAL FUEL GAS COMPANY New Accounting Pronouncements 00000 In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133). This state- ment was subsequently amended by SFAS 137, “Accounting for Derivative Instruments and Hedging Activities – Deferral of the Effective Date of FASB Statement No. 133,” and by SFAS 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of Statement 133.” For a discussion of the impact on the Company, see disclosure in Note A - Summary of Significant Accounting Policies in Item 8 of this report. Effects of Inflation 00000 Although the rate of inflation has been relatively low over the past few years, the Company’s operations remain sensitive to increases in the rate of inflation because of its capital spending and the regulated nature of a significant portion of its business. The Company is including the following cautionary statement in this combined Annual Report to Shareholders/Form 10-K to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make avail- able forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cau- tionary statements. Certain statements contained herein, including those which are designated with a “*”, are forward-looking statements and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The forward- looking statements contained herein are based on various assumptions, many of which are based, in turn, upon further assumptions. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including, without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statement: 1. Changes in economic conditions, demographic patterns and weather conditions; 2. Changes in the availability or price of natural gas and oil; 3. Inability to obtain new customers or retain existing ones; 4. Significant changes in competitive factors affecting the Company; 5. Governmental/regulatory actions and initiatives, including those affecting acquisitions, financings, allowed rates of return, industry and rate structure, franchise renewal, and environmental/safety requirements; 6. Unanticipated impacts of restructuring initiatives in the natural gas and electric industries; 7. Significant changes from expectations in actual capital expenditures and operating expenses and unantici- pated project delays or changes in project costs; 8. The nature and projected profitability of pending and potential projects and other investments; 9. Occurrences affecting the Company’s ability to obtain funds from operations, debt or equity to finance needed capital expenditures and other investments; 10. Uncertainty of oil and gas reserve estimates; Safe Harbor for Forward-Looking Statements 56 NATIONAL FUEL GAS COMPANY 11. Ability to successfully identify and finance oil and gas property acquisitions and ability to operate and integrate existing and any subsequently acquired business or properties; 12. Ability to successfully identify, drill for and produce economically viable natural gas and oil reserves; 13. Changes in the availability or price of derivative financial instruments; 14. Changes in the price of natural gas or oil and the related effect given the accounting treatment or valua- tion of these financial instruments; 15. Inability of the various counterparties to meet their obligations with respect to the Company’s financial instruments; 16. Regarding foreign operations - changes in foreign trade and monetary policies, laws and regulations related to foreign operations, political and governmental changes, inflation and exchange rates, taxes and operating conditions; 17. Significant changes in tax rates or policies or in rates of inflation or interest; 18. Significant changes in the Company’s relationship with its employees and the potential adverse effects if labor disputes or grievances were to occur; or 19. Changes in accounting principles or the application of such principles to the Company. The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof. I T E M•7A Quantitative and Qualitative Disclosures About Market Risk I T E M•8 Financial Statements and Supplementary Data Refer to the “Market Risk Sensitive Instruments” section in Item 7, MD&A. Financial Statements: Report of Independent Accountants 58 Consolidated Statements of Income and Earnings Reinvested in the Business, Index to Financial Statements 00000 Supplementary Data three years ended September 30, 2000 59 Consolidated Balance Sheets at September 30, 2000 and 1999 60 Consolidated Statement of Cash Flows, three years ended September 30, 2000 62 Consolidated Statement of Comprehensive Income, three years ended September 30, 2000 63 Notes to Consolidated Financial Statements 64 Financial Statement Schedules: For the three years ended September 30, 2000 II-Valuation and Qualifying Accounts 89 All other schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or Notes thereto. Supplementary data that is included in Note K - Quarterly Financial Data (unaudited) and Note M - Supplementary Information for Oil and Gas Producing Activities, appears under this Item, and reference is made thereto. 57 NATIONAL FUEL GAS COMPANY Report of Management Management is responsible for the preparation and integrity of the Company’s financial statements. The financial statements have been prepared in accordance with generally accepted accounting principles and necessarily include some amounts that are based on management’s best estimates and judgment. The Company maintains a system of internal accounting and administrative controls and an ongoing program of internal audits that management believes provide reasonable assurance that assets are safeguarded and that transactions are properly recorded and executed in accordance with management’s authorization. The Company’s financial statements have been examined by our independent accountants, PricewaterhouseCoopers LLP, which also conducts a review of internal controls to the extent required by generally accepted auditing standards. The Audit Committee of the Board of Directors, composed solely of outside directors, meets with management, internal auditors and PricewaterhouseCoopers LLP to review planned audit scope and results and to discuss other matters affecting internal accounting controls and financial reporting. The independent accountants have direct access to the Audit Committee and periodically meet with it without management representatives present. Report of Independent Accountants To the Board of Directors and Shareholders of National Fuel Gas Company In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of National Fuel Gas Company and its subsidiaries at September 30, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2000, 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 accom- panying index presents fairly, in all material respects, the information set forth therein when read in conjunc- tion 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 support- ing 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. PricewaterhouseCoopers LLP Buffalo, New York October 23, 2000 58 NATIONAL FUEL GAS COMPANY Consolidated Statements of Income and Earnings Reinvested in the Business Year Ended September 30 (Thousands of Dollars, Except Per Common Share Amounts) 2000 1999 1998 Income Operating Revenues $1,425,277 $1,263,274 $1,248,000 Operating Expenses Purchased Gas Fuel Used in Heat and Electric Generation Operation Maintenance Property, Franchise and Other Taxes Depreciation, Depletion and Amortization Impairment of Oil and Gas Producing Properties Income Taxes Operating Income Other Income Income Before Interest Charges and Minority Interest in Foreign Subsidiaries Interest Charges Interest on Long-Term Debt Other Interest Minority Interest in Foreign Subsidiaries Income Before Cumulative Effect Cumulative Effect of Change in Accounting for Depletion Net Income Available for Common Stock Balance at Beginning of Year Dividends on Common Stock Balance at End of Year Basic Earnings Per Common Share: Income Before Cumulative Effect Cumulative Effect of Change in Accounting For Depletion Net Income Available for Common Stock Diluted Earnings Per Common Share: Income Before Cumulative Effect Cumulative Effect of Change in Accounting For Depletion Net Income Available for Common Stock Weighted Average Common Shares Outstanding: Used in Basic Calculation Used in Diluted Calculation See Notes to Consolidated Financial Statements 503,617 54,893 326,933 23,450 78,878 142,170 — 77,068 405,925 55,788 304,919 23,881 91,146 124,778 — 64,829 441,746 37,837 295,618 25,793 92,817 117,238 128,996 24,024 1,207,009 1,071,266 1,164,069 218,268 10,408 192,008 12,343 83,931 35,870 228,676 204,351 119,801 67,195 32,890 100,085 (1,384) 127,207 — 127,207 472,517 599,724 73,877 65,402 22,296 87,698 (1,616) 115,037 — 115,037 428,112 543,149 70,632 53,154 32,130 85,284 (2,213) 32,304 (9,116) 23,188 472,595 495,783 67,671 $ 525,847 $ 472,517 $ 428,112 $3.25 — $3.25 $3.21 — $3.21 $2.98 — $2.98 $2.95 — $2.95 $0.85 (0.24) $0.61 $0.84 (0.24) $0.60 39,116,921 39,583,100 38,663,981 39,041,728 38,316,397 38,703,526 59 Earnings Reinvested in the Business NATIONAL FUEL GAS COMPANY Consolidated Balance Sheets At September 30 (Thousands of Dollars) Assets Property, Plant and Equipment Less - Accumulated Depreciation, Depletion and Amortization Current Assets Cash and Temporary Cash Investments Receivables – Net Unbilled Utility Revenue Gas Stored Underground Materials and Supplies - at average cost Unrecovered Purchased Gas Costs Prepayments Other Assets Recoverable Future Taxes Unamortized Debt Expense Other Regulatory Assets Deferred Charges Other See Notes to Consolidated Financial Statements 2000 1999 $3,829,637 1,146,246 $3,390,875 1,029,643 2,683,391 2,361,232 32,125 122,127 27,105 55,795 25,145 29,681 32,293 324,271 29,222 97,828 18,674 41,099 23,631 4,576 35,072 250,102 84,199 19,841 17,518 12,497 95,171 87,724 21,717 25,214 14,266 82,331 229,226 231,252 $3,236,888 $2,842,586 60 NATIONAL FUEL GAS COMPANY At September 30 (Thousands of Dollars) 2000 1999 Capitalization and Liabilities Capitalization: Common Stock Equity Common Stock, $1 Par Value Authorized — 200,000,000 Shares; Issued and Outstanding — 39,329,803 Shares and 38,837,499 Shares, respectively Paid In Capital Earnings Reinvested in the Business Accumulated Other Comprehensive Income Total Common Stock Equity Long-Term Debt, Net of Current Portion Total Capitalization Minority Interest in Foreign Subsidiaries Current and Accrued Liabilities Notes Payable to Banks and Commercial Paper Current Portion of Long-Term Debt Accounts Payable Amounts Payable to Customers Other Accruals and Current Liabilities Deferred Credits Accumulated Deferred Income Taxes Taxes Refundable to Customers Unamortized Investment Tax Credit Other Deferred Credits Commitments and Contingencies See Notes to Consolidated Financial Statements $ 39,330 452,217 525,847 (29,957) 987,437 953,622 $ 38,837 431,952 472,517 (4,013) 939,293 822,743 1,941,059 1,762,036 23,031 27,589 619,502 11,262 88,970 9,583 84,961 814,278 326,994 14,410 9,951 107,165 458,520 — 393,495 69,608 82,747 5,934 87,310 639,094 275,008 14,814 11,007 113,038 413,867 — $3,236,888 $2,842,586 61 NATIONAL FUEL GAS COMPANY Consolidated Statement of Cash Flows Year Ended September 30 (Thousands of Dollars) 2000 1999 1998 Operating Activities Net Income Available for Common Stock Adjustments to Reconcile Net Income to Net Cash $127,207 $115,037 $23,188 Provided by Operating Activities Cumulative Effect of a Change in Accounting for Depletion Impairment of Oil and Gas Producing Properties Depreciation, Depletion and Amortization Deferred Income Taxes Minority Interest in Foreign Subsidiaries Other Change in: Receivables and Unbilled Utility Revenue Gas Stored Underground and Materials and Supplies Unrecovered Purchased Gas Costs Prepayments Accounts Payable Amounts Payable to Customers Other Accruals and Current Liabilities Other Assets Other Liabilities — — 142,170 41,858 1,384 4,540 — — 124,778 14,030 1,616 7,018 9,116 128,996 117,238 (26,237) 2,213 (6,378) (26,825) (18,161) 45,200 (13,707) (25,105) 3,436 (16,372) 3,649 (4,642) 8,537 (7,884) (7,280) 1,740 (15,322) 22,871 153 10,931 (906) 10,999 (2,744) (6,316) 829 (24,975) (4,735) (15,481) 36 9,913 Net Cash Provided by Operating Activities 238,246 267,504 249,863 Capital Expenditures Investment in Subsidiaries, Net of Cash Acquired Investment in Partnerships Other Net Cash Used in Investing Activities Change in Notes Payable to Banks and Commercial Paper Net Proceeds from Issuance of Long-Term Debt Reduction of Long-Term Debt Proceeds from Issuance of Common Stock Dividends Paid on Common Stock Dividends Paid to Minority Interest Net Cash Provided by (Used in) Financing Activities Effect of Exchange Rates on Cash Net Increase (Decrease) in Cash and Temporary Cash Investments Cash and Temporary Cash Investments at Beginning of Year (269,371) (123,809) (4,442) 13,283 (256,120) (5,774) (3,633) 6,687 (390,118) (111,966) (5,453) 7,583 (384,339) (258,840) (499,954) 226,477 149,334 (167,426) 14,278 (73,046) (152) 149,465 (469) 67,195 198,217 (213,849) 10,735 (69,878) (246) (7,826) (2,053) 229,387 198,750 (103,867) 7,853 (66,959) (253) 264,911 1,578 2,903 29,222 (1,215) 30,437 16,398 14,039 Cash and Temporary Cash Investments at End of Year $ 32,125 $ 29,222 $30,437 Supplemental Disclosure of Cash Flow Information Cash Paid For: Interest Income Taxes See Notes to Consolidated Financial Statements $ 97,042 41,928 $ 75,813 48,995 $46,242 64,537 Investing Activities Financing Activities 62 NATIONAL FUEL GAS COMPANY Consolidated Statement of Comprehensive Income Year Ended September 30 (Thousands of Dollars) 2000 1999 1998 Net Income Available for Common Stock $127,207 $115,037 $23,188 Foreign Currency Translation Adjustment Unrealized Gain on Securities Available for Sale Arising During the Period Reclassification Adjustment for Gains on Securities Available for Sale Realized in Net Income (27,463) (11,737) 9,350 2,441 (103) 706 — — — Other Comprehensive Income (Loss), Before Tax: (25,125) (11,031) 9,350 Income Tax Expense Related to Unrealized Gain on Securities Available for Sale Arising During the Period Reclassification Adjustment for Income Tax Expense on Gains on Securities Available for Sale Realized in Net Income Income Taxes – Net 855 (36) 819 247 — 247 — — — Other Comprehensive Income (Loss), Net of Tax (25,944) (11,278) 9,350 Comprehensive Income See Notes to Consolidated Financial Statements $101,263 $103,759 $32,538 63 NATIONAL FUEL GAS COMPANY Notes to Consolidated Financial Statements N O T E•A Summary of Significant Accounting Policies Principles of Consolidation The Company consolidates its majority owned subsidiaries. The equity method is used to account for minority owned entities. All significant intercompany balances and transactions are eliminated. The preparation of the consolidated financial statements in conformity with generally accepted account- ing principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Reclassification Certain prior year amounts have been reclassified to conform with current year presentation. Regulation The Company is subject to regulation by certain state and federal authorities. The Company has accounting policies which conform to generally accepted accounting principles, as applied to regulated enterprises, and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. Reference is made to Note B - Regulatory Matters for further discussion. In the International segment, rates charged for the sale of thermal energy and electric energy at the retail level are subject to regulation and audit in the Czech Republic by the Czech Ministry of Finance. The regu- lation of electric energy rates at the retail level indirectly impacts the rates charged by the International segment for its electric energy sales at the wholesale level. Revenues Revenues are recorded as bills are rendered, except that service supplied but not billed is reported as “Unbilled Utility Revenue” and is included in operating revenues for the year in which service is furnished. Unrecovered Purchased Gas Costs and Refunds The Company’s rate schedules in the Utility segment contain clauses that permit adjustment of revenues to reflect price changes from the cost of purchased gas included in base rates. Differences between amounts cur- rently recoverable and actual adjustment clause revenues, as well as other price changes and pipeline and storage company refunds not yet includable in adjustment clause rates, are deferred and accounted for as either unrecovered purchased gas costs or amounts payable to customers. Estimated refund liabilities to ratepayers represent management’s current estimate of such refunds. Reference is made to Note B - Regulatory Matters for further discussion. Property, Plant and Equipment The principal assets of the Utility and Pipeline and Storage segments, consisting primarily of gas plant in service, are recorded at the historical cost when originally devoted to service in the regulated businesses, as required by regulatory authorities. Oil and gas property acquisition, exploration and development costs are capitalized under the full-cost method of accounting. All costs directly associated with property acquisition, exploration and development activities are capitalized, up to certain specified limits. If capitalized costs exceed these limits at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. Due to significant declines in oil prices in 1998, capitalized costs under the full-cost method of accounting exceeded these 64 NATIONAL FUEL GAS COMPANY limits at March 31, 1998. The Company was required to recognize an impairment of its oil and gas produc- ing properties in the quarter ended March 31, 1998. This charge amounted to $129.0 million (pretax) and reduced net income for 1998 by $79.1 million. Maintenance and repairs of property and replacements of minor items of property are charged directly to maintenance expense. The original cost of the regulated subsidiaries’ property, plant and equipment retired, and the cost of removal less salvage, are charged to accumulated depreciation. Depreciation, Depletion and Amortization Depreciation, depletion and amortization are computed by application of either the straight-line method or the units of production method, in amounts sufficient to recover costs over the estimated service lives of property in service, and for oil and gas properties, based on quantities produced in relation to proved reserves (see discussion of change in method of depletion for oil and gas properties below). The costs of unevaluated oil and gas properties are excluded from this computation. For timber properties, depletion, determined on a property by property basis, is charged to operations based on the annual amount of timber cut in relation to the total amount of recoverable timber. The provisions for depreciation, depletion and amortization, as a per- centage of average depreciable property, were 4.2% in 2000, 4.1% in 1999 and 4.3% in 1998 on a consoli- dated basis. Cumulative Effect of Change in Accounting Effective October 1, 1997, the Company changed its method of depletion for oil and gas properties from the gross revenue method to the units of production method. The units of production method was applied retroactively to prior years to determine the cumulative effect through October 1, 1997. This cumulative effect reduced earnings for 1998 by $9.1 million, net of income tax. Depletion of oil and gas properties for 2000, 1999 and 1998 was computed under the units of production method. Gas Stored Underground - Current In the Utility segment, gas stored underground - current in the amount of $29.3 million is carried at lower of cost or market, on a last-in, first-out (LIFO) method. Based upon the average price of spot market gas purchased in September 2000, including transportation costs, the current cost of replacing the inventory of gas stored underground - current exceeded the amount stated on a LIFO basis by approximately $104.2 million at September 30, 2000. All other gas stored underground is carried at lower of cost or market on either an average cost or first-in, first-out method. Unamortized Debt Expense Costs associated with the issuance of debt by the Company are deferred and amortized over the lives of the related issues. Costs associated with the reacquisition of debt related to rate-regulated subsidiaries are deferred and amortized over the remaining life of the issue or the life of the replacement debt in order to match regulatory treatment. Foreign Currency Translation The functional currency for the Company’s foreign operations is the local currency. Asset and liability accounts are translated at the rate of exchange on the balance sheet date. Revenues and expenses are translated at the average exchange rate during the period. Foreign currency translation adjustments are recorded as a component of Accumulated Other Comprehensive Income. Income Taxes The Company and its domestic subsidiaries file a consolidated federal income tax return. Investment Tax Credit, prior to its repeal in 1986, was deferred and is being amortized over the estimated useful lives of the related property, as required by regulatory authorities having jurisdiction. No provision has been made for domestic income taxes applicable to undistributed earnings of foreign subsidiaries as the amounts are considered to be permanently reinvested outside the U.S. 65 Financial Instruments Unrealized gains or losses from the Company’s investments in marketable equity securities are recorded as a component of Accumulated Other Comprehensive Income. Reference is made to Note F – Financial Instruments for further discussion. The Company uses a variety of financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil. These instruments can be categorized as price swap agreements, no cost collars, options and futures contracts. Gains or losses from price swap agreements are accrued in operating revenues at the contract settlement dates. Options and futures contracts that have not been designated as hedges are marked-to-market on a quarterly basis with gains or losses recorded in operating revenues. For options that have been designated as hedges, premiums are amortized on a straight- line basis over the life of the option. Gains or losses resulting from the exercise of options that have been des- ignated as hedges are reflected in operating revenues when the hedged commodity transaction occurs. Gains or losses from futures contracts that have been designated as hedges are recorded in other deferred credits or deferred debits until the hedged commodity transaction occurs, at which point they are reflected in operat- ing revenues. The Company also uses an interest rate swap to eliminate interest rate fluctuations on certain variable rate debt. Gains or losses are accrued in interest charges at the contract settlement dates. In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133). This statement was subsequently amended by SFAS 137, “Accounting for Derivative Instruments and Hedging Activities—Deferral of the Effective Date of FASB Statement No. 133,” and by SFAS 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of Statement 133.” SFAS 133, as amended, establishes accounting and reporting standards for derivative instru- ments, including certain derivative instruments embedded in other contracts, and for hedging activities. This statement requires the Company to recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The intended use of the derivatives and their designation as either a fair value hedge, a cash flow hedge, or a foreign currency hedge will determine when the gains or losses on the derivatives are to be reported in earnings and when they are to be reported as a component of other comprehensive income. The Company will adopt SFAS 133, as amended, during the first quarter of fiscal 2001. The cumulative effect of this change will decrease fiscal 2001 net income by approximately $0.3 million after tax. The cumulative effect of this change will decrease other comprehensive income by approximately $69.8 million after tax. Accumulated Other Comprehensive Income (Loss) The components of Accumulated Other Comprehensive Income (Loss) are as follows: Year Ended September 30 (Thousands) Cumulative Foreign Currency Translation Adjustment Net Unrealized Gain on Securities Available for Sale Accumulated Other Comprehensive Loss 2000 1999 $(31,935) 1,978 $(29,957) $(4,472) 459 $(4,013) Consolidated Statement of Cash Flows For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of generally three months or less to be cash equivalents. NATIONAL FUEL GAS COMPANY 66 NATIONAL FUEL GAS COMPANY Earnings Per Common Share Basic earnings per common share is computed by dividing income available for common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. The only potentially dilutive securities the Company has out- standing are stock options. The diluted weighted average shares outstanding shown on the Consolidated Statement of Income reflects the potential dilution as a result of these stock options as determined using the Treasury Stock Method. N O T E•B Regulatory Matters Regulatory Assets and Liabilities The Company has recorded the following regulatory assets and liabilities: At September 30 (Thousands) 2000 1999 Regulatory Assets: Recoverable Future Taxes (Note C) Unrecovered Purchased Gas Costs (Note A) Unamortized Debt Expense (Note A) Pension and Post-Retirement Benefit Costs (Note G) Other Total Regulatory Assets Regulatory Liabilities: Amounts Payable to Customers (Note A) New York Rate Settlements Taxes Refundable to Customers (Note C) Pension and Post-Retirement Benefit Costs(1) (Note G) Other(1) Total Regulatory Liabilities Net Regulatory Position (1) Included in Other Deferred Credits on the Consolidated Balance Sheets. $84,199 29,681 13,454 16,370 1,148 144,852 9,583 21,315 14,410 17,439 2,975 65,722 $87,724 4,576 15,223 21,217 3,997 132,737 5,934 18,913 14,814 26,087 3,226 68,974 $79,130 $63,763 If for any reason the Company ceases to meet the criteria for application of regulatory accounting treat- ment for all or part of their operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the balance sheet and included in income of the period in which the discontinuance of regulatory accounting treatment occurs. Such amounts would be classified as an extraordinary item. New York Rate Settlements With respect to utility services provided in New York, the Company has entered into rate settlements approved by the State of New York Public Service Commission (NYPSC). The rate settlements provide for a sharing mechanism, whereby earnings above a 12% return on equity (11.5% effective October 1, 2000) are to be shared equally between shareholders and ratepayers. As a result of this sharing mechanism, the Company had liabilities of $11.2 million and $8.6 million at September 30, 2000 and 1999, respectively. Of these amounts, $7.6 million and $3.0 million are included in Amounts Payable to Customers at September 30, 2000 and 1999, respectively, to reflect the amounts estimated to be passed back to customers in the following year. Other aspects of the settlements include a special reserve of $7.8 million and $7.4 67 NATIONAL FUEL GAS COMPANY million at September 30, 2000 and 1999, respectively, to be applied against the Company’s incremental costs resulting from the NYPSC’s gas restructuring effort and a “refund pool” of $5.6 million and $3.5 million at September 30, 2000 and 1999, respectively. The refund pool is an accumulation of certain refunds from upstream pipeline companies and certain credits which can be used to offset certain specific expense items. Various other regulatory liabilities have also been created through the New York rate settlements and amounted to $4.2 million and $2.5 million at September 30, 2000 and 1999, respectively. N O T E•C Income Taxes The components of federal, state and foreign income taxes included in the Consolidated Statement of Income are as follows: Year Ended September 30 (Thousands) Operating Expenses: Current Income Taxes - Federal State Deferred Income Taxes - Federal State Foreign Income Taxes Other Income: Deferred Investment Tax Credit Minority Interest in Foreign Subsidiaries Cumulative Effect of Change in Accounting for Depletion 2000 1999 1998 $26,352 13,067 29,604 2,495 5,550 77,068 (1,051) (259) — $43,467 6,215 11,149 1,244 2,754 64,829 (729) (642) — $40,740 6,635 (21,687) (5,997) 4,333 24,024 (665) (1,218) (5,737) Total Income Taxes $75,758 $63,458 $16,404 The U.S. and foreign components of income (loss) before income taxes are as follows: Year Ended September 30 (Thousands) 2000 1999 1998 U.S. Foreign $182,813 20,152 $202,965 $169,038 9,457 $178,495 $31,127 8,465 $39,592 Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income before income taxes. The following is a reconciliation of this difference: Year Ended September 30 (Thousands) 2000 1999 1998 Income Tax Expense, Computed at Federal Statutory Rate of 35% Increase (Reduction) in Taxes Resulting from: State Income Taxes Depreciation Property Retirements Keyman Life Insurance Prior Years’ Tax Adjustment Miscellaneous Total Income Taxes $71,038 $62,473 $ 13,857 10,115 1,925 (1,470) (964) 137 (5,023) 4,848 1,872 (833) (502) (1,362) (3,038) 986 2,186 (1,609) (774) 2,846 (1,088) $75,758 $63,458 $16,404 68 NATIONAL FUEL GAS COMPANY Significant components of the Company’s deferred tax liabilities and assets were as follows: Year Ended September 30 (Thousands) Deferred Tax Liabilities: Property, Plant and Equipment Other Total Deferred Tax Liabilities Deferred Tax Assets: Other Total Net Deferred Income Taxes 2000 1999 $375,660 23,776 399,436 (72,442) $326,994 $305,688 19,045 324,733 (49,725) $275,008 Regulatory liabilities representing the reduction of previously recorded deferred income taxes associated with rate-regulated activities that are expected to be refundable to customers amounted to $14.4 million and $14.8 million at September 30, 2000 and 1999, respectively. Also, regulatory assets, representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of prior ratemaking practices amounted to $84.2 million and $87.7 million at September 30, 2000 and 1999, respectively. N O T E•D Capitalization SUMMARY OF CHANGES IN COMMON STOCK EQUITY (Thousands, Except Per Share Amounts) Balance at September 30, 1997 Net Income Available for Common Stock Dividends Declared on Common Stock ($1.77 Per Share) Other Comprehensive Income, Net of Tax Common Stock Issued Under Stock and Benefit Plans Balance at September 30, 1998 Net Income Available for Common Stock Dividends Declared on Common Stock ($1.83 Per Share) Other Comprehensive Income, Net of Tax Common Stock Issued Under Stock and Benefit Plans Balance at September 30, 1999 Net Income Available for Common Stock Dividends Declared on Common Stock ($1.89 Per Share) Other Comprehensive Income, Net of Tax Acquisition of Natural Gas Assets Common Stock Issued Under Stock and Benefit Plans Common Stock Shares Amount Paid In Capital 38,166 $38,166 $405,028 303 38,469 303 38,469 11,211 416,239 368 38,837 368 38,837 15,713 431,952 55 438 55 438 2,757 17,508 Earnings Reinvested in the Business Accumulated Other Comprehensive Income $472,595 23,188 (67,671) 428,112 115,037 (70,632) 472,517 127,207 (73,877) $(2,085) 9,350 7,265 (11,278) (4,013) (25,944) Balance at September 30, 2000 39,330 $39,330 $452,217 $525,847(1) $(29,957) (1) The availability of consolidated earnings reinvested in the business for dividends payable in cash is limited under terms of the indentures covering long-term debt. At September 30, 2000, $451.5 million of accumulated earnings was free of such limitations. 69 NATIONAL FUEL GAS COMPANY 70 Common Stock The Company has various plans which allow shareholders, customers and employees to purchase shares of Company common stock. The National Fuel Direct Stock Purchase and Dividend Reinvestment Plan allows shareholders to reinvest cash dividends or make cash investments in the Company’s common stock and provides residential customers the opportunity to acquire shares of Company common stock without the payment of any brokerage commissions or service charges in connection with such acquisitions. The 401(k) Plans allow employees the opportunity to invest in Company common stock, in addition to a variety of other investment alternatives. At the discretion of the Company, shares purchased under these plans are either original issue shares purchased directly from the Company or shares purchased on the open market by an agent. The Company also has a Director Stock Program under which it issues shares of Company common stock to its non-employee directors as partial consideration for their services as directors. Shareholder Rights Plan In 1996, the Company’s Board of Directors adopted a shareholder rights plan (Plan). Effective April 30, 1999, the Plan was amended and is now embodied in an Amended and Restated Rights Agreement. The holders of the Company’s common stock have one right (Right) for each of their shares. Each Right, which will initially be evidenced by the Company’s common stock certificates representing the out- standing shares of common stock, entitles the holder to purchase one-half of one share of common stock at a purchase price of $130 per share, being $65 per half share, subject to adjustment (Purchase Price). The Rights become exercisable upon the occurrence of a distribution date. At any time following a distribution date, each holder of a Right may exercise its right to receive common stock (or, under certain circumstances, other property of the Company) having a value equal to two times the Purchase Price of the Right then in effect. However, the Rights are subject to redemption or exchange by the Company prior to their exercise as described below. A distribution date would occur upon the earlier of (i) ten days after the public announcement that a person or group has acquired, or obtained the right to acquire, beneficial ownership of the Company’s common stock or other voting stock having 10% or more of the total voting power of the Company’s common stock and other voting stock and (ii) ten days after the commencement or announcement by a person or group of an intention to make a tender or exchange offer that would result in that person acquir- ing, or obtaining the right to acquire, beneficial ownership of the Company’s common stock or other voting stock having 10% or more of the total voting power of the Company’s common stock and other voting stock. In certain situations after a person or group has acquired beneficial ownership of 10% or more of the total voting power of the Company’s stock as described above, each holder of a Right will have the right to exercise its Rights to receive common stock of the acquiring company having a value equal to two times the Purchase Price of the Right then in effect. These situations would arise if the Company is acquired in a merger or other business combination or if 50% or more of the Company’s assets or earning power are sold or transferred. At any time prior to the end of the business day on the tenth day following the announcement that a person or group has acquired, or obtained the right to acquire, beneficial ownership of 10% or more of the total voting power of the Company, the Company may redeem the Rights in whole, but not in part, at a price of $.01 per Right, payable in cash or stock. A decision to redeem the Rights requires the vote of 75% of the Company’s full Board of Directors. Also, at any time following the announcement that a person or group has acquired, or obtained the right to acquire, beneficial ownership of 10% or more of the total voting power of the Company, 75% of the Company’s full Board of Directors may vote to exchange the Rights, in whole or in part, at an exchange rate of one share of common stock, or other property deemed to have the same value, per Right, subject to certain adjustments. NATIONAL FUEL GAS COMPANY After a distribution date, Rights that are owned by an acquiring person will be null and void. Upon exercise of the Rights, the Company may need additional regulatory approvals to satisfy the requirements of the Rights Agreement. The Rights will expire on July 31, 2008, unless they are exchanged or redeemed earlier than that date. The Rights have anti-takeover effects because they will cause substantial dilution of the common stock if a person attempts to acquire the Company on terms not approved by the Board of Directors. Stock Option and Stock Award Plans The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: incentive stock options, nonqualified stock options, stock appreciation rights, restricted stock, performance units or performance shares. Stock options under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no option is exercisable less than one year or more than ten years after the date of each grant. For the years ended September 30, 2000, 1999 and 1998, no compensation expense was recognized for options granted under these plans. Had compensation expense for stock options granted under the Company’s stock option and stock award plans been determined based on fair value at the grant dates, the Company’s net income and earnings per share would have been reduced to the pro forma amounts below: Year Ended September 30 Net Income (Thousands): As reported Pro forma Earnings Per Common Share: Basic - As reported Basic - Pro forma Diluted - As reported Diluted - Pro forma 2000 1999 1998 $127,207 $123,107 $115,037 $111,385 $23,188 $18,859 $3.25 $3.15 $3.21 $3.11 $2.98 $2.88 $2.95 $2.85 $0.61 $0.49 $0.60 $0.49 Transactions involving option shares for all plans are summarized as follows: Outstanding at September 30, 1997 Granted in 1998 Exercised in 1998 Forfeited in 1998 Outstanding at September 30, 1998 Granted in 1999 Exercised in 1999 Forfeited in 1999 Outstanding at September 30, 1999 Granted in 2000 Exercised in 2000(1) Forfeited in 2000 Outstanding at September 30, 2000 Option shares exercisable at September 30, 2000 Option shares available for future grant at September 30, 2000(2) Number of Shares Subject to Option Weighted Average Exercise Price 2,174,346 770,000 (205,200) (7,250) 2,731,896 753,400 (111,504) (9,700) 3,364,092 891,100 (227,742) (13,900) 4,013,550 3,005,354 1,099,830 $33.21 $44.44 $27.41 $41.68 $36.79 $46.70 $28.41 $37.41 $39.29 $43.74 $30.16 $46.15 $40.77 $39.63 (1) In connection with exercising these options, 58,458, 16,531 and 44,580 shares were surrendered and canceled during 2000, 1999 and 1998, respectively. (2) Including shares available for restricted stock grants. 71 The weighted average fair value per share of options granted in 2000, 1999 and 1998 was $8.34, $7.43 and $7.91, respectively. These weighted average fair values were estimated on the date of grant using a bino- mial option pricing model with the following weighted average assumptions: Year Ended September 30 Quarterly Dividend Yield Annual Standard Deviation (Volatility) Risk Free Rate Expected Term - in Years 2000 1.07% 19.05% 6.74% 5.5 1999 0.97% 18.86% 4.74% 5.0 1998 0.98% 16.48% 5.77% 5.5 The following table summarizes information about options outstanding at September 30, 2000: Range of Exercise Price Options Outstanding Number Outstanding at 9/30/00 Weighted Average Remaining Contractual Life $23.81 - $35.72 $35.73 - $49.72 697,026 3,316,524 3.8 years 7.8 years Weighted Average Exercise Price $29.34 $43.17 Options Exercisable Number Exercisable at 9/30/00 697,026 2,308,328 Weighted Average Exercise Price $29.34 $42.73 Restricted stock is subject to restrictions on vesting and transferability. Restricted stock awards entitle the participants to full dividend and voting rights. The market value of restricted stock on the date of the award is being recorded as compensation expense over the periods during which the vesting restrictions exist. Certificates for shares of restricted stock awarded under the Company’s stock options and stock award plans are held by the Company during the periods in which the restrictions on vesting are effective. The following table summarizes the awards of restricted stock over the past three years: Year Ended September 30 Shares of Restricted Stock Awarded Weighted Average Market Price of Stock on Award Date 2000 7,589 $48.94 1999 6,580 $46.06 1998 7,609 $44.88 As of September 30, 2000, 75,693 shares of non-vested restricted stock were outstanding. Vesting restrictions will lapse as follows: 2001 – 35,104 shares; 2002 – 8,000 shares; 2003 – 12,925 shares; 2004 – 7,000 shares; 2005 – 6,000 shares; 2006 – 6,000 shares; and 2009 – 664 shares. Stock Appreciation Rights (SARs) give the grantee the right to cash compensation equal to the apprecia- tion in the market price of Company common stock from the grant date to the exercise date. SARs are marked-to-market each quarter with the related increase or decrease in expense recognized in the income statement. At September 30, 2000, 1,381,000 SARs were outstanding at a weighted average exercise price of $38.54. Compensation expense related to SARs and restricted stock under the Company’s stock plans was $14.9 million, $1.0 million and $4.1 million for the years ended September 30, 2000, 1999 and 1998, respectively. Redeemable Preferred Stock As of September 30, 2000, there were 10,000,000 shares of $1 par value Preferred Stock authorized but unissued. NATIONAL FUEL GAS COMPANY 72 NATIONAL FUEL GAS COMPANY Long-Term Debt The outstanding long-term debt is as follows: At September 30 (Thousands) National Fuel Gas Company: Debentures: 7-3/4% due February 2004 Medium-Term Notes: 6.00% to 8.48% due February 2000 to August 2027(1) Other Notes Total Long-Term Debt Less Current Portion 2000 1999 $125,000 $125,000 799,000 924,000 40,884 964,884 11,262 699,000 824,000 68,351 892,351 69,608 $953,622 $822,743 (1) Includes $50 million of 8.48% medium-term notes due July 2024 which are callable at a redemption price of 105.94% through July 2001. The redemption price will decline in subsequent years. It also includes $100 million of 6.214% medium-term notes due August 2027 which are putable by debt holders only on August 12, 2002, at par. The aggregate principal amounts of long-term debt maturing for the next five years and thereafter are as follows: $11.3 million in 2001, $8.5 million in 2002, $158.6 million in 2003, $233.7 million in 2004, $2.7 million in 2005 and $550.1 million thereafter. N O T E•E Short-Term Borrowings The Company has SEC authorization under the Public Utility Holding Company Act of 1935, as amended, to borrow and have outstanding as much as $750.0 million of short-term debt at any time through December 31, 2002. The Company historically has borrowed short-term funds either through bank loans or the issuance of commercial paper. As for the former, the Company maintains uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under these lines of credit are made at competitive market rates. These credit lines are revocable at the option of the financial institutions and are reviewed on an annual basis. At September 30, 2000, the Company had outstanding short-term notes payable to banks and commercial paper of $419.5 million (domestic = $401.2 million; foreign = $18.3 million) and $200.0 million, respectively. At September 30, 1999, the Company had outstanding notes payable to banks and commercial paper of $246.0 million (domestic = $244.8 million; foreign = $1.2 million) and $147.5 million, respectively. The weighted average interest rate on domestic notes payable to banks was 6.81% and 5.55% at September 30, 2000 and 1999, respectively. The interest rate on the foreign notes payable to banks was 5.73% and 6.35% at September 30, 2000 and 1999, respectively. The weighted average interest rate on commercial paper was 6.62% and 5.49% at September 30, 2000 and 1999, respectively. 73 NATIONAL FUEL GAS COMPANY N O T E•F Financial Instruments Fair Values The fair market value of the Company’s long-term debt is estimated based on quoted market prices of similar issues having the same remaining maturities, redemption terms and credit ratings. Based on these cri- teria, the fair market value of long-term debt, including current portion, was as follows: At September 30 (Thousands) Long-Term Debt 2000 Carrying Amount 2000 Fair Value 1999 Carrying Amount 1999 Fair Value $964,884 $928,066 $892,351 $867,056 The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay. Temporary cash investments, notes payable to banks and commercial paper are stated at amounts which approximate their fair value due to the short-term maturities of those financial instruments. Investments in life insurance are stated at their cash surrender values as discussed below. Investments in a mutual fund and the stock of an insurance company (marketable equity securities), as discussed below, are stated at fair value based on quoted market prices. Investments Other assets includes cash surrender values of insurance contracts and marketable equity securities. The cash surrender values of the insurance contracts amounted to $49.4 million and $44.2 million at September 30, 2000 and 1999, respectively. The marketable equity securities amounted to $10.0 million and $7.3 million at September 30, 2000 and 1999, respectively. The insurance contracts and marketable equity securities are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees. Derivative Financial Instruments The Company uses a variety of derivative financial instruments to manage a portion of the market risk asso- ciated with the fluctuations in the price of natural gas and crude oil. These instruments can be categorized as price swap agreements, no cost collars, options and futures contracts and are highly correlated with the phys- ical side of the natural gas and crude oil transactions that are related to these instruments. The instruments are not held for trading purposes. The fair value of these instruments at September 30, 2000 is a net liability and is represented as the amount that the Company would have to pay to terminate the instruments. However, the calculation of this liability to the counterparties does not consider the physical side of the natural gas and crude oil transactions that are related to the financial instruments. Under the price swap agreements, the Company receives monthly payments from (or makes payments to) other parties based upon the difference between a fixed and a variable price as specified by the agreement. The variable price is either a crude oil price quoted on the New York Mercantile Exchange (NYMEX) or a quoted natural gas price in “Inside FERC.” At September 30, 2000, the Company had natural gas price swap agreements covering a notional amount of 44.9 Bcf extending through 2003 at a weighted average fixed rate of $3.34 per Mcf. The Company also had crude oil price swap agreements covering a notional amount of 10,361,895 bbls extending through 2003 at a weighted average fixed rate of $21.75 per bbl. At September 30, 2000, the Company would have had to pay $106.2 million to terminate the price swap agreements. Under the no cost collars, the Company receives monthly payments from (or makes payments to) other parties when a variable price falls below an established floor price (the Company receives payment from the counterparty) or exceeds an established ceiling price (the Company pays the counterparty). The variable 74 NATIONAL FUEL GAS COMPANY price is either a crude oil price quoted on the NYMEX or a natural gas price quoted in “Inside FERC.” At September 30, 2000, the Company had no cost collars on natural gas covering a notional amount of 6.6 Bcf extending through 2001 with a weighted average floor price of $3.83 per Mcf and a weighted average ceiling price of $5.75 per Mcf. The Company also had no cost collars on crude oil covering a notional amount of 4,725,000 bbls extending through 2004 with a weighted average floor price of $22.49 per bbl and a weighted average ceiling price of $28.44 per bbl. At September 30, 2000, the Company would have had to pay $5.8 million to terminate the no cost collars. At September 30, 2000, the Company had purchased options outstanding on natural gas covering a notional amount of 31.1 Bcf extending through 2001 at a weighted average strike price of $4.76 per Mcf. The Company also had sold options outstanding on natural gas covering a notional amount of 37.9 Bcf extending through 2001 at a weighted average strike price of $4.76 per Bcf. The Company also had sold options outstanding on crude oil covering a notional amount of 368,000 bbls extending through 2001 at a weighted average strike price of $15.25 per bbl. At September 30, 2000, the Company would have had to pay $9.8 million to terminate all of these options. At September 30, 2000, the Company had futures contracts covering 3.9 Bcf of gas on a net basis (net short position) extending through 2002 at a weighted average contract price of $4.20 per Mcf. The Company would have had to pay $5.5 million to terminate the futures contracts at September 30, 2000. The Company may be exposed to credit risk on some of its derivative financial instruments. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on an ongoing basis monitors counterparty credit exposure. The Company uses an interest rate swap to eliminate interest rate fluctuations on certain variable rate debt. Under the terms of the interest rate swap, which extends until 2002, the Company pays a fixed rate of 8.31% and receives a floating rate of six month Prague Interbank Offered Rate (PRIBOR). At September 30, 2000, the Company would have had to pay $1.4 million to terminate the interest rate swap. N O T E•G Retirement Plan and Other Post-Retirement Benefits The Company has a tax-qualified, noncontributory, defined-benefit retirement plan (Retirement Plan) that covers substantially all domestic employees of the Company. The Company provides health care and life insurance benefits for substantially all domestic retired employees under a post-retirement benefit plan (Post-Retirement Plan). The Company’s policy is to fund the Retirement Plan with at least an amount necessary to satisfy the minimum funding requirements of applicable laws and regulations and not more than the maximum amount deductible for federal income tax purposes. The Company has established Voluntary Employees’ Beneficiary Association (VEBA) trusts for its Post-Retirement Plan. Contributions to the VEBA trusts are tax deductible, subject to limitations contained in the Internal Revenue Code and regulations and are made to fund employees’ post-retirement health care and life insurance benefits, as well as benefits as they are paid to current retirees. Retirement Plan and Post-Retirement Plan assets primarily consist of equity and fixed income investments or units in commingled funds or money market funds. The Company is fully recovering its net periodic pension and post-retirement benefit costs in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorization. For financial reporting purposes, the difference between the amounts of pension cost and post-retirement 75 NATIONAL FUEL GAS COMPANY 76 benefit cost recoverable in rates and the amounts of such costs as determined by their actuary under applicable accounting principles is recorded as either a regulatory asset or liability, as appropriate. Pension and post-retirement benefit costs reflect the amount recovered from customers in rates during the year. Under the NYPSC’s policies, the Company segregates the amount of such costs collected in rates, but not yet contributed to the Retirement and Post-Retirement Plans, into a regulatory liability account. This liability accrues interest at the NYPSC mandated interest rate and this interest cost is included in pension and post- retirement benefit costs. For purposes of disclosure, the liability also remains in the disclosed pension and post-retirement benefit liability amount because it has not yet been contributed. Retirement Plan Reconciliations of the Benefit Obligation, Retirement Plan Assets and Funded Status, as well as the compo- nents of Net Periodic Benefit Cost and the Weighted Average Assumptions are as follows: Year Ended September 30 (Thousands) 2000 1999 1998 Change in Benefit Obligation Benefit Obligation at Beginning of Period Service Cost Interest Cost Amendments Actuarial (Gain) Loss Benefits Paid Benefit Obligation at End of Period Change in Plan Assets Fair Value of Assets at Beginning of Period Actual Return on Plan Assets Employer Contribution Benefits Paid Fair Value of Assets at End of Period Reconciliation of Funded Status Funded Status Unrecognized Net Actuarial Gain Unrecognized Transition Asset Unrecognized Prior Service Cost Accrued Benefit Cost Weighted Average Assumptions as of September 30 Discount Rate Expected Return on Plan Assets Rate of Compensation Increase Year Ended September 30 (Thousands) Components of Net Periodic Benefit Cost Service Cost Interest Cost Expected Return on Plan Assets Amortization of Prior Service Cost Amortization of Transition Amount Recognition of Actuarial Loss Early Retirement Window Net Amortization and Deferral for Regulatory Purposes Net Periodic Benefit Cost $538,796 11,692 37,954 — (20,216) (32,332) $535,894 $537,958 36,584 27,726 (32,332) $569,936 $ 34,042 (62,008) (11,148) 10,943 $ (28,171) $532,250 12,676 36,299 1,691 (13,598) (30,522) $538,796 $509,393 47,888 11,199 (30,522) $537,958 $ (838) (45,853) (14,864) 12,048 $(49,507) $462,377 10,655 35,485 — 52,446 (28,713) $532,250 $473,205 59,415 5,486 (28,713) $509,393 $ (22,857) (12,659) (18,580) 11,369 $ (42,727) 2000 1999 1998 7.50% 8.50% 5.00% $11,692 37,954 (41,077) 1,106 (3,716) 60 — 206 $ 6,225 7.25% 8.50% 5.00% $12,676 36,299 (38,158) 1,012 (3,716) 2,833 7,032 2,721 $20,699 7.00% 8.50% 5.00% $10,655 35,485 (35,724) 1,065 (3,716) 981 — 4,829 $13,575 NATIONAL FUEL GAS COMPANY The effect of the discount rate change in 2000 was to decrease the Benefit Obligation by $15.3 million as of the end of the period. The effect of the discount rate change in 1999 was to decrease the Benefit Obligation as of the end of the period by $15.9 million. Other Post-Retirement Benefits Reconciliations of the Benefit Obligation, Post-Retirement Plan Assets and Funded Status, as well as the components of Net Periodic Benefit Cost and the Weighted Average Assumptions are as follows: Year Ended September 30 (Thousands) 2000 1999 1998 Change in Benefit Obligation Benefit Obligation at Beginning of Period Service Cost Interest Cost Plan Participants’ Contributions Actuarial (Gain) Loss Benefits Paid Benefit Obligation at End of Period Change in Plan Assets Fair Value of Assets at Beginning of Period Actual Return on Plan Assets Employer Contribution Plan Participants’ Contributions Benefits Paid Fair Value of Assets at End of Period Reconciliation of Funded Status Funded Status Unrecognized Net Actuarial (Gain) Loss Unrecognized Transition Obligation Accrued Benefit Cost Weighted Average Assumptions as of September 30 Discount Rate Expected Return on Plan Assets Rate of Compensation Increase Year Ended September 30 (Thousands) Components of Net Periodic Benefit Cost Service Cost Interest Cost Expected Return on Plan Assets Amortization of Transition Obligation Amortization of (Gain) Loss Net Amortization and Deferral for Regulatory Purposes Net Periodic Benefit Cost $255,615 4,156 18,142 414 (355) (11,512) $266,460 $149,884 18,527 19,044 414 (11,512) $176,357 $ (90,103) (8,676) 92,653 $ (6,126) $ 256,983 4,493 17,635 673 (13,542) (10,627) $ 255,615 $ 122,870 17,345 19,623 673 (10,627) $ 149,884 $(105,731) (2,396) 99,780 $ (8,347) $ 218,370 4,022 17,122 867 27,014 (10,412) $ 256,983 $ 98,639 14,602 19,174 867 (10,412) $ 122,870 $(134,113) 19,660 106,907 $ (7,546) 2000 1999 1998 7.50% 8.50% 5.00% 7.25% 8.50% 5.00% 7.00% 8.50% 5.00% $ 4,156 18,142 (12,574) 7,127 (24) 7,269 $ 24,096 $ 4,493 17,635 (10,134) 7,127 1,304 1,774 $ 4,022 17,122 (8,099) 7,127 683 915 $ 22,199 $ 21,770 The effect of the discount rate change in 2000 was to decrease the Benefit Obligation by $8.9 million. The effect of the discount rate change in 1999 was to decrease the Benefit Obligation by $9.1 million. The health care trend assumptions were changed in 2000 to better reflect anticipated future experience. The effect of the changed medical care, prescription drug and Medicare Part B assumptions mentioned below, was to increase the Accumulated Post-Retirement Benefit Obligation by $13.7 million. 77 NATIONAL FUEL GAS COMPANY The annual rate of increase in the per capita cost of covered medical care benefits was assumed to be 9.0% for 1998, 8.0% for 1999, 10.0% for 2000 and gradually decline to 5.5% by the year 2005 and remain level thereafter. The annual rate of increase for medical care benefits provided by healthcare maintenance organizations was assumed to be 7.5% in 1998, 7.0% in 1999, 10.0% in 2000 and gradually decline to 5.5% by the year 2005 and remain level thereafter. The annual rate of increase in the per capita cost of covered prescription drug benefits was assumed to be 9.0% for 1998, 8.0% for 1999, 15.0% for 2000 and gradually decline to 5.5% by the year 2005 and remain level thereafter. The annual rate of increase in the per capita Medicare Part B Reimbursement was assumed to be 9.0% for 1998, 8.0% for 1999, 10.0% for 2000 and gradually decline to 5.5% by the year 2005 and remain level thereafter. The health care cost trend rate assumptions used to calculate the per capita cost of covered medical care benefits have a significant effect on the amounts reported. If the health care cost trend rates were increased by 1% in each year, the Benefit Obligation as of October 1, 2000 would be increased by $36.8 million. This 1% change would also have increased the aggregate of the service and interest cost components of net peri- odic post-retirement benefit cost for 2000 by $3.9 million. If the health care cost trend rates were decreased by 1% in each year, the Benefit Obligation as of October 1, 2000 would be decreased by $29.2 million. This 1% change would also have decreased the aggregate of the service and interest cost components of net peri- odic post-retirement benefit cost for 2000 by $3.3 million. N O T E•H Commitments and Contingencies Environmental Matters The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remedia- tion) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. The Company has estimated its remaining clean-up costs related to the sites described below in (i) and (ii) will be in the range of $6.4 million to $7.6 million. The minimum estimated liability of $6.4 million has been recorded on the Consolidated Balance Sheet at September 30, 2000. Other than discussed below, the Company is currently not aware of any material exposure to environmental liabilities. However, adverse changes in environmental regulations, new information or other factors could impact the Company. (i) Former Manufactured Gas Plant Sites The Company has incurred or is incurring clean-up costs at four former manufactured gas plant sites in New York and Pennsylvania. Remediation is substantially complete at a site where the Company has been designated by the New York Department of Environmental Conservation (DEC) as a potentially responsible party (PRP) and is also engaged in litigation with the DEC and the party who bought that site from the Company’s predecessor. At a second site, remediation is in progress and is expected to be completed in 2001. At a third site the Company is negotiating with the DEC for clean-up under a voluntary program. The fourth is a site allegedly containing, among other things, manufactured gas plant waste and is in the investi- gation stage. (ii) Third Party Waste Disposal Sites The Company has been identified by the DEC or the United States Environmental Protection Agency as one of a number of companies considered to be PRPs with respect to two waste disposal sites in New York which were operated by unrelated third parties. The PRPs are alleged to have contributed to the materials that may have been collected at such waste disposal sites by the site operators. The ultimate cost to the Company with respect to the remediation of these sites will depend on such factors as the remediation plan 78 NATIONAL FUEL GAS COMPANY selected, the extent of site contamination, the number of additional PRPs at each site and the portion of responsibility, if any, attributed to the Company. The remediation has been completed at one site, with final payments pending. At a second waste disposal site, the remedial design has been agreed to and the parties are in settlement discussions. (iii) Other The Company received, in 1998 and again in October 1999, notice that the DEC believes the Company is responsible for contamination discovered at an additional former manufactured gas plant site in New York. The Company, however, has not been named as a PRP. The Company responded to these notices that other companies operated that site before its predecessor did, that liability could be imposed upon it only if hazardous substances were disposed of at the site during a period when the site was operated by its predecessor, and that it was unaware of any such disposal. The Company has not incurred any clean-up costs at this site nor has it been able to reasonably estimate the probability or extent of potential liability. Other The Company, in its Utility segment, has entered into contractual commitments in the ordinary course of business including commitments to purchase capacity on nonaffiliated pipelines to meet customer gas supply needs. The majority of these contracts (representing 87% of contracted demand capacity) expire within the next five years. Costs incurred under these contracts are purchased gas costs, subject to state commission review, and are being recovered in customer rates. Management believes, to the extent any stranded pipeline costs are generated by the unbundling of services in the Utility segment’s service territory, such costs will be recoverable from customers. The Company is involved in litigation arising in the normal course of its business. In addition to the regulatory matters discussed in Note B - Regulatory Matters, the Company is involved in other regulatory matters arising in the normal course of business that involve rate base, cost of service and purchased gas cost issues. While the resolution of such litigation or other regulatory matters could have a material effect on earnings and cash flows in the year of resolution, none of this litigation, and none of these other regulatory matters, are expected to have a material adverse effect on the financial condition of the Company at this time. N O T E•I Business Segment Information The Company has six reportable segments: Utility, Pipeline and Storage, Exploration and Production, International, Energy Marketing and Timber. The breakdown of the Company’s reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors. The Utility segment operations are regulated by the NYPSC and the Pennsylvania Public Utility Commission (PaPUC) and are carried out by Distribution Corporation. Distribution Corporation sells natural gas to retail customers and provides natural gas transportation services in western New York and northwestern Pennsylvania. The Pipeline and Storage segment operations are regulated by the Federal Energy Regulatory Commission (FERC) and are carried out by Supply Corporation and SIP. Supply Corporation transports and stores natural gas for utilities (including Distribution Corporation), natural gas marketers (including NFR) and pipeline companies in the northeastern United States markets. SIP, although not regulated itself by the FERC, holds a one-third partnership interest in the Independence Pipeline Company, whose rates, services and other matters are or will be regulated by the FERC. 79 The Exploration and Production segment, through Seneca, is engaged in exploration for, and develop- ment and purchase of, natural gas and oil reserves in the Gulf Coast of Texas and Louisiana, in California, in Wyoming, in the Appalachian region of the United States and in the provinces of Manitoba, Alberta and Saskatchewan in Canada. Seneca’s production is, for the most part, sold to purchasers located in the vicinity of its wells. The International segment’s operations are carried out by Horizon. Horizon engages in foreign energy projects through the investment of its indirect subsidiaries as the sole or partial owner of various business entities. Horizon’s current emphasis is the Czech Republic where, through its subsidiaries, it owns majority interests in companies having district heating and power generation plants in the northern Bohemia region of the Czech Republic. The Energy Marketing segment is comprised of NFR’s operations. NFR is engaged in the retail market- ing of natural gas, the marketing of electricity and the performance of energy management services for indus- trial, commercial, public authority and residential end-users located in the northeastern United States. The Timber segment’s operations are carried out by the Northeast division of Seneca and by Highland. This segment has timber holdings in the northeastern United States and several sawmills and kilns in Pennsylvania. The data presented in the tables below reflect the reportable segments and reconciliations to consoli- dated amounts. The accounting policies of the segments are the same as those described in Note A - Summary of Significant Accounting Policies. Sales of products or services between segments are billed at reg- ulated rates or at market rates, as applicable. Expenditures for long-lived assets include additions to property, plant and equipment and equity investments in corporations (stock acquisitions) and/or partnerships, net of any cash acquired. The Company evaluates segment performance based on income before discontinued oper- ations, extraordinary items and cumulative effects of changes in accounting (when applicable). When these items are not applicable, the Company evaluates performance based on net income. Pipeline and Storage Exploration and Production Utility International Energy Marketing Timber Total Reportable Segments Corporate and Intersegment Eliminations All Other Total Consolidated $ 827,231 $ 81,434 88,225 13,311 19,228 31,655 $ 237,845 $104,736 $133,929 $ 39,172 $1,424,347 $ 225 42,034 — 12,353 — 774 — 4,750 107,678 104,877 930 4,415 262 $ — $1,425,277 — 100,085 (112,093) (5,054) 35,842 38,362 23,379 22,172 69,583 19,413 11,110 (1,783) 209 (4,372) 1,948 3,816 142,071 77,608 97 (205) 2 (335) 142,170 77,068 57,662 31,614 34,877 3,282 (7,790) 6,133 125,778 (371) 1,800 127,207 55,799 35,806(1) 280,049 9,767 89 13,542 395,052 3,725 — 398,777 $1,219,496 $552,059 $1,088,066 $202,622 $ 47,121 $107,402 $3,216,766 $21,930 $(1,808) $3,236,888 (1) Amount includes $1.2 million in a stock-for-asset swap. NATIONAL FUEL GAS COMPANY Year Ended September 30, 2000 (Thousands) Revenue from External Customers Intersegment Revenues Interest Expense Depreciation, Depletion and Amortization Income Tax Expense Segment Profit (Loss): Net Income Expenditures for Additions to Long-Lived Assets At September 30, 2000 (Thousands) Segment Assets 80 NATIONAL FUEL GAS COMPANY Year Ended September 30, 1999 (Thousands) Revenue from External Customers Intersegment Revenues Interest Expense Depreciation, Depletion and Amortization Income Tax Expense Segment Profit (Loss): Net Income Expenditures for Additions to Long-Lived Assets At September 30, 1999 (Thousands) Pipeline and Storage Exploration and Production Utility International Energy Marketing Timber Total Reportable Segments Corporate and Intersegment Eliminations All Other Total Consolidated $ 801,053 $ 82,994 85,789 13,147 6,302 29,659 $140,212 $107,045 — 11,451 6,782 34,409 $99,088 — 234 $31,117 $1,261,509 98,873 91,108 — 2,208 $1,765 $ — $1,263,274 — 87,698 — (98,873) (3,510) 100 34,215 34,741 22,690 22,439 55,750 2,992 10,473 15 165 1,138 1,476 2,788 124,769 64,113 7 55 2 661 124,778 64,829 56,875 39,765 7,127 2,276 2,054 4,769 112,866 (162) 2,333 115,037 46,974 34,873 97,586 33,412 302 52,314 265,461 66 — 265,527 Segment Assets $1,178,185 $542,962 $727,557 $255,042 $18,676 $98,830 $2,821,252 $7,351 $13,983 $2,842,586 Year Ended September 30, 1998 (Thousands) Revenue from External Customers Intersegment Revenues Interest Expense Depreciation, Depletion and Amortization Income Tax Pipeline and Storage Exploration and Production Utility International Energy Marketing Timber Total Reportable Segments Corporate and Intersegment Eliminations All Other Total Consolidated $ 867,802 $ 84,218 86,765 15,232 3,378 44,639 $113,194 $ 76,259 $87,187 $17,805 $1,246,465 101,221 90,124 11,078 21,454 — 7,188 — 1,580 — 31 $1,535 $ — $1,248,000 — 85,284 — (101,221) (4,873) 33 33,459 21,816 50,937 7,309 91 3,527 117,139 97 2 117,238 Expense (Benefit) 30,076 29,644 (39,478) 2,158 471 1,445 24,316 119 (411) 24,024 Significant Noncash Item: Impairment of Oil and Gas Producing Properties Segment Profit (Loss): Income Before Cumulative Effect of Change in Accounting Expenditures for Additions to Long-Lived Assets At September 30, 1998 (Thousands) — — 128,996 — — — 128,996 — — 128,996 51,788 39,852 (64,110) 1,279 787 1,904 31,500 143 661 32,304 50,680 29,145 323,627 96,987 320 6,778 507,537 — — 507,537 Segment Assets $1,171,645 $526,738 $673,706 $242,339 $16,944 $45,507 $2,676,879 $5,216 $2,364 $2,684,459 81 NATIONAL FUEL GAS COMPANY GEOGRAPHIC INFORMATION For the Year Ended September 30 (Thousands) Revenues from External Customers(1): United States Czech Republic Canada At September 30, (Thousands) Long-Lived Assets: United States Czech Republic Canada (1) Revenue is based upon the country in which the sale originates. 2000 1999 1998 $1,292,190 104,736 28,351 $1,156,229 107,045 — $1,171,741 76,259 — $1,425,277 $1,263,274 $1,248,000 $2,480,406 183,274 248,937 $2,369,840 215,457 — $2,258,817 215,125 — $2,912,617 $2,585,297 $2,473,942 N O T E•J Stock Acquisitions In June 2000, the Company acquired the outstanding shares of Tri Link Resources, Ltd. (Tri Link) a Calgary, Alberta based oil and gas exploration and production company. The cost of acquiring the outstand- ing shares of Tri Link was approximately $123.8 million. Upon completing this acquisition, Tri Link was amalgamated under the name of National Fuel Exploration Corp. (NFE). NFE’s results of operations were incorporated into the Company’s consolidated financial statements for the period subsequent to the comple- tion of the acquisition of Tri Link on June 15, 2000. In May 1998, the Company acquired the outstanding shares of HarCor Energy, Inc. (HarCor) for approximately $32.6 million ($29.8 million, net of cash acquired). HarCor’s results of operations were incor- porated into the Company’s consolidated financial statements for the period subsequent to the completion of the tender offer in May 1998. During 1998 and 1999, the Company purchased majority ownership interests in Severoc˘eské teplárny, a.s. (SCT), První severozápadní teplárenská, a.s. (PSZT) and Jablonecká teplárenská a realitní, a.s. (JTR) (a majority owned subsidiary of SCT). The cost of acquiring these shares in 1998 was $89.4 million ($82.2 million, net of cash acquired). In 1999, an additional $5.8 million was invested ($5.7 million, net of cash acquired). In 2000, SCT and PSZT merged and the merged company was renamed United Energy, a.s. All of the acquisitions disclosed above were accounted for in accordance with the purchase method. The goodwill resulting from these acquisitions is being amortized over a twenty-year period and is recorded in Other Assets. This goodwill amounted to $8.7 million and $9.5 million at September 30, 2000 and 1999, respectively. Details of the stock acquisitions made by the Company during 2000, 1999 and 1998 are as follows: Year Ended September 30 (Millions) Assets acquired Liabilities assumed Existing investment at acquisition Cash acquired at acquisition Cash paid, net of cash acquired 2000 $259.9 (136.1) — — $123.8 1999 $13.5 (7.3) (0.4) (0.1) $5.7 1998 $313.5 (172.6) (18.9) (10.0) $112.0 82 NATIONAL FUEL GAS COMPANY N O T E•K Quarterly Financial Data (unaudited) In the opinion of management, the following quarterly information includes all adjustments necessary for a fair statement of the results of operations for such periods. Per common share amounts are calculated using the weighted average number of shares outstanding during each quarter. The total of all quarters may differ from the per common share amounts shown on the Consolidated Statement of Income. Those per common share amounts are based on the weighted average number of shares outstanding for the entire fiscal year. Because of the seasonal nature of the Company’s heating business, there are substantial variations in opera- tions reported on a quarterly basis. Quarter Ended 2000 12/31/1999 3/31/2000 6/30/2000 (1) 9/30/2000 Operating Revenues Operating Income (Thousands, except per common share amounts) $377,031 $517,767 $281,201 $249,278 $70,237 $91,074 $30,043 $26,914 1999 (Thousands, except per common share amounts) 12/31/1998 3/31/1999 6/30/1999 9/30/1999 $340,422 $483,404 $248,658 $190,790 $56,835 $83,475 $31,319 $20,379 Net Income Available for Common Stock Earnings Per Common Share Basic Diluted $44,868 $71,051 $ 9,070(2) $ 2,218(3) $37,619(4) $61,145 $11,840(5) $ 4,433(6) $1.15 $1.82 $0.23 $0.06 $0.98 $1.58 $0.31 $0.11 $1.14 $1.81 $0.23 $0.06 $0.97 $1.57 $0.30 $0.11 (1) As revised. (2) Includes expense of $14.2 million related to mark-to-market and other revenue adjustments related to derivative financial instruments and expense of $3.5 million related to SAR’s. (3) Includes expense of $6.6 million related to SAR’s, expense of $3.7 million for adjustments related to the New York rate settlement, expense of $1.6 million related to the recording of a loss contingency on fixed price sales contracts and income of $3.9 million related to mark-to-market and other revenue adjustments related to derivative financial instruments. (4) Includes income of $3.9 million related to IRS audit settlement and expense of $3.5 million related to an early retirement offer. (5) Includes expense of $3.8 million related to SAR’s, expense of $1.1 million related to an early retirement offer and income of $1.0 million for lost and unaccounted for (LAUF) gas adjustment related to 1998. (6) Includes income of $1.6 million for LAUF gas adjustment related to 1999 and income of $1.6 million related to a gain on stock received from the demutualization of an insurance company. N O T E•L Market for Common Stock and Related Shareholder Matters (unaudited) At September 30, 2000, there were 21,164 holders of National Fuel Gas Company common stock. The common stock is listed and traded on the New York Stock Exchange. Information related to restrictions on the payment of dividends can be found in Note D - Capitalization. The quarterly price ranges and quarterly dividends declared for the fiscal years ended September 30, 2000 and 1999, are shown below: Quarter Ended 2000 12/31/99 3/31/00 6/30/00 9/30/00 1999 12/31/98 3/31/99 6/30/99 9/30/99 Price Range High Low Dividends Declared $52.94 $46.75 $51.94 $58.81 $49.63 $46.50 $50.00 $49.75 $46.00 $39.38 $43.13 $48.13 $44.88 $39.25 $37.50 $44.63 $.465 $.465 $.480 $.480 $.450 $.450 $.465 $.465 83 NATIONAL FUEL GAS COMPANY N O T E•M Supplementary Information for Oil and Gas Producing Activities The following supplementary information is presented in accordance with SFAS 69, “Disclosures about Oil and Gas Producing Activities,” and related SEC accounting rules. All monetary amounts are expressed in U.S. dollars. CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES At September 30 (Thousands) Proved Properties Unproved Properties Less - Accumulated Depreciation, Depletion and Amortization 2000 1999 $1,218,871 152,360 1,371,231 390,267 $980,964 $880,470 92,097 972,567 315,675 $656,892 Costs related to unproved properties are excluded from amortization as they represent unevaluated properties that require additional drilling to determine the existence of oil and gas reserves. Following is a summary of such costs excluded from amortization at September 30, 2000: (Thousands) Acquisition Costs Total as of September 30, 2000 Year Costs Incurred 2000 1999 1998 Prior $152,360 $106,665 $5,608 $31,640 $8,447 COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES Year Ended September 30 (Thousands) United States Property Acquisition Costs: Proved Unproved Exploration Costs Development Costs Canada Property Acquisition Costs: Proved Unproved Exploration Costs Development Costs Total Property Acquisition Costs: (1) Proved Unproved Exploration Costs Development Costs 2000 1999 1998 $ 2,848 19,066 50,163 72,039 144,116 157,835 76,504 573 11,013 245,925 160,683 95,570 50,736 83,052 $ 2,798 11,530 52,141 30,985 97,454 $189,201 88,369 74,421 23,887 375,878 — — — — — — — — — — 2,798 11,530 52,141 30,985 189,201 88,369 74,421 23,887 (1) Total proved and unproved property acquisition costs for 2000 of $256.3 million include $236.5 million related to the Tri Link acquisition (now known as NFE). Total proved and unproved property acquisition costs for 1998 of $277.6 million include amounts related to the HarCor, Bakersfield Energy and Whittier Trust properties acquired in 1998 of $87.0 million, $25.3 million and $141.1 million, respectively. $390,041 $97,454 $375,878 84 NATIONAL FUEL GAS COMPANY RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES Year Ended September 30 (Thousands, Except Per Mcfe Amounts) 2000 1999 1998 United States Operating Revenues: Natural Gas (includes revenues from sales to affiliates of $237, $6,365 and $11,065, respectively) Oil, Condensate and Other Liquids Total Operating Revenues(1) Production/Lifting Costs Depreciation, Depletion and Amortization ($0.97, $0.89 and $0.96 per Mcfe of production) Impairment of Oil and Gas Producing Properties(2) Income Tax Expense (Benefit) Results of Operations for Producing Activities (excluding corporate overheads and interest charges) Canada Operating Revenues: Natural Gas Oil, Condensate and Other Liquids Total Operating Revenues (1) Production/Lifting Costs Depreciation, Depletion and Amortization ($0.77, $ - and $ - per Mcfe of production) Income Tax Expense Results of Operations for Producing Activities (excluding corporate overheads and interest charges) Total Operating Revenues: Natural Gas (includes revenues from sales to affiliates of $237, $6,365 and $11,065, respectively) Oil, Condensate and Other Liquids Total Operating Revenues(1) Production/Lifting Costs Depreciation, Depletion and Amortization ($0.95, $0.89 and $0.96 per Mcfe of production) Impairment of Oil and Gas Producing Properties(2) Income Tax Expense (Benefit) Results of Operations for Producing Activities (excluding corporate overheads and interest charges) (1) Exclusive of hedging gains and losses. See further discussion in Note F - Financial Instruments. (2) See discussion of impairment in Note A - Summary of Significant Accounting Policies. $137,336 107,645 244,981 33,979 64,624 — 52,656 $ 81,734 51,592 133,326 28,119 54,439 — 16,255 $ 89,284 31,770 121,054 23,622 50,221 128,996 (28,949) 93,722 34,513 (52,836) 485 26,320 26,805 7,858 4,321 6,121 8,505 137,821 133,965 271,786 41,837 68,945 — 58,777 — — — — — — — — — — — — — — 81,734 51,592 133,326 28,119 54,439 — 16,255 89,284 31,770 121,054 23,622 50,221 128,996 (28,949) $102,227 $ 34,513 $(52,836) 85 NATIONAL FUEL GAS COMPANY Reserve Quantity Information (unaudited) The Company’s proved oil and gas reserves are located in the United States and Canada. The estimated quantities of proved reserves disclosed in the table below are based upon estimates by qualified Company geologists and engineers and are audited by independent petroleum engineers. Such estimates are inherently imprecise and may be subject to substantial revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Gas MMcf U.S. Canada Total U.S. Oil Mbbl Canada Total Proved Developed and Undeveloped Reserves: September 30, 1997 Extensions and Discoveries Revisions of Previous Estimates Production Sales of Minerals in Place Purchases of Minerals in Place and Other September 30, 1998 Extensions and Discoveries Revisions of Previous Estimates Production Sales of Minerals in Place Purchases of Minerals in Place and Other September 30, 1999 Extensions and Discoveries Revisions of Previous Estimates Production Sales of Minerals in Place Purchases of Minerals in Place and Other September 30, 2000 Proved Developed Reserves: September 30, 1997 September 30, 1998 September 30, 1999 September 30, 2000 232,449 40,293 (18,623) (36,474) — 107,420 325,065 46,423 (13,091) (37,166) (439) — 232,449 — 40,293 — (18,623) — (36,474) — — — 107,420 — 325,065 — 46,423 — (13,091) — (37,166) (439) — — — — — 320,792 34,641 — (8,001) — (41,670) (192) (7,444) — 320,792 34,641 (8,001) (41,478) (7,444) — 298,510 194,454 230,508 222,929 227,250 17,981 640 (4,191) (2,614) — 54,775 66,591 3,716 9,808 (4,016) (280) — 75,819 2,167 4,000 (4,248) (227) — — — — — — — — — — — — — 1,765 — (899) — 17,981 640 (4,191) (2,614) — 54,775 66,591 3,716 9,808 (4,016) (280) — 75,819 3,932 4,000 (5,147) (227) 3,349 3,157 3,349 301,667 — 41,320 41,320 77,511 42,186 119,697 — 194,454 — 230,508 — 222,929 230,407 3,157 11,354 48,081 57,333 66,074 — — — 35,130 11,354 48,081 57,333 101,204 Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (unaudited) The Company cautions that the following presentation of the standardized measure of discounted future net cash flows is intended to be neither a measure of the fair market value of the Company’s oil and gas proper- ties, nor an estimate of the present value of actual future cash flows to be obtained as a result of their devel- opment and production. It is based upon subjective estimates of proved reserves only and attributes no value to categories of reserves other than proved reserves, such as probable or possible reserves, or to unproved acreage. Furthermore, it is based on year-end prices and costs adjusted only for existing contractual changes, and it assumes an arbitrary discount rate of 10%. Thus, it gives no effect to future price and cost changes certain to occur under the widely fluctuating political and economic conditions of today’s world. 86 NATIONAL FUEL GAS COMPANY The standardized measure is intended instead to provide a somewhat better means for comparing the value of the Company’s proved reserves at a given time with those of other oil- and gas-producing companies than is provided by a simple comparison of raw proved reserve quantities. Year Ended September 30 (Thousands) 2000 1999 1998 United States Future Cash Inflows Less: Future Production Costs Future Development Costs Future Income Tax Expense at Applicable Statutory Rate Future Net Cash Flows Less: 10% Annual Discount for Estimated Timing of Cash Flows Standardized Measure of Discounted Future Net Cash Flows Canada Future Cash Inflows Less: Future Production Costs Future Development Costs Future Income Tax Expense at Applicable Statutory Rate Future Net Cash Flows Less: 10% Annual Discount for Estimated Timing of Cash Flows Standardized Measure of Discounted Future Net Cash Flows Total Future Cash Inflows Less: Future Production Costs Future Development Costs Future Income Tax Expense at Applicable Statutory Rate Future Net Cash Flows Less: 10% Annual Discount for Estimated Timing of Cash Flows Standardized Measure of Discounted Future Net Cash Flows $3,886,499 $2,402,308 $1,547,216 600,243 179,565 1,006,366 2,100,325 560,459 185,617 477,205 1,179,027 413,753 160,884 245,120 727,459 859,950 471,768 260,688 1,240,375 707,259 466,771 1,083,598 277,067 21,399 286,148 498,984 221,227 277,757 — — — — — — — — — — — — — — 4,970,097 2,402,308 1,547,216 877,310 200,964 1,292,514 2,599,309 560,459 185,617 477,205 1,179,027 413,753 160,884 245,120 727,459 1,081,177 471,768 260,688 $1,518,132 $707,259 $466,771 87 NATIONAL FUEL GAS COMPANY The principal sources of change in the standardized measure of discounted future net cash flows were as follows: Year Ended September 30 (Thousands) United States Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year Sales, Net of Production Costs Net Changes in Prices, Net of Production Costs Purchases of Minerals in Place Sales of Minerals in Place Extensions and Discoveries Changes in Estimated Future Development Costs Previously Estimated Development Costs Incurred Net Change in Income Taxes at Applicable Statutory Rate Revisions of Previous Quantity Estimates Accretion of Discount and Other Standardized Measure of Discounted Future Net Cash Flows at End of Year Canada Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year Sales, Net of Production Costs Net Changes in Prices, Net of Production Costs Purchases of Minerals in Place Sales of Minerals in Place Extensions and Discoveries Changes in Estimated Future Development Costs Previously Estimated Development Costs Incurred Net Change in Income Taxes at Applicable Statutory Rate Revisions of Previous Quantity Estimates Accretion of Discount and Other Standardized Measure of Discounted Future Net Cash Flows at End of Year Total Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year Sales, Net of Production Costs Net Changes in Prices, Net of Production Costs Purchases of Minerals in Place Sales of Minerals in Place Extensions and Discoveries Changes in Estimated Future Development Costs Previously Estimated Development Costs Incurred Net Change in Income Taxes at Applicable Statutory Rate Revisions of Previous Quantity Estimates Accretion of Discount and Other Standardized Measure of Discounted Future Net Cash Flows at End of Year 2000 1999 1998 $707,259 (211,002) 795,408 — (11,914) 186,818 (82,270) 88,322 (292,371) 20,736 39,389 $466,771 (53,615) 317,356 — (2,706) 122,894 (97,082) 72,349 (232,085) 40,964 72,413 $383,200 (97,432) (180,853) 364,102 — 36,844 (104,181) 28,514 57,190 (75,136) 54,523 1,240,375 707,259 466,771 — (18,948) — 424,072 — 2,979 — — (150,057) — 19,711 277,757 707,259 (229,950) 795,408 424,072 (11,914) 189,797 (82,270) 88,322 (442,428) 20,736 59,100 — — — — — — — — — — — — — — — — — — — — — — — — 466,771 (53,615) 317,356 — (2,706) 122,894 (97,082) 72,349 (232,085) 40,964 72,413 383,200 (97,432) (180,853) 364,102 — 36,844 (104,181) 28,514 57,190 (75,136) 54,523 $1,518,132 $707,259 $466,771 88 NATIONAL FUEL GAS COMPANY Schedule II VALUATION AND QUALIFYING ACCOUNTS (Thousands) Description Year Ended September 30, 2000 Reserve for Doubtful Accounts Year Ended September 30, 1999 Reserve for Doubtful Accounts Year Ended September 30, 1998 Reserve for Doubtful Accounts Balance at Beginning of Period Additions Charged to Costs and Expenses Additions Charged to Other Accounts(1) Deductions(2) Balance at End of Period $7,842 $15,177 $ — $11,006 $12,013 $6,232 $15,337 $1 $13,728 $ 7,842 $8,291 $15,861 $746 $18,666 $ 6,232 (1) Represents opening balance sheet reserve plus exchange rate impact of translating the Czech koruna to the U.S. dollar for Horizon. (2) Amounts represent net accounts receivable written-off. I T E M•9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None Part III I T E M•10 Directors and Executive Officers of the Registrant The information required by this item concerning the directors of the Company is omitted pursuant to Instruction G of Form 10-K since the Company’s definitive Proxy Statement for its February 15, 2001 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2000. The information concerning directors is set forth in the definitive Proxy Statement under the captions entitled “Nominees for Election as Directors for Three-Year Terms to Expire 2003,” “Directors Whose Terms Expire in 2002,” “Directors Whose Terms Expire in 2001,” and “Compliance with Section 16(a) of the Securities Exchange Act of 1934” and is incorporated herein by reference. Information concerning the Company’s executive officers can be found in Part I, Item 1, of this report. I T E M•11 Executive Compensation The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company’s definitive Proxy Statement for its February 15, 2001 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2000. The information concerning executive compensation is set forth in the definitive Proxy Statement under the captions “Executive Compensation” and “Compensation Committee Interlocks and Insider Participation and, excepting the “Report of the Compensation Committee” and the “Corporate Performance Graph,” is incorporated herein by reference. 89 NATIONAL FUEL GAS COMPANY I T E M•12 Security Ownership of Certain Beneficial Owners and Management (a) Security Ownership of Certain Beneficial Owners The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company’s definitive Proxy Statement for its February 15, 2001 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2000. The information concerning security ownership of certain beneficial owners is set forth in the definitive Proxy Statement under the caption “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference. (b) Security Ownership of Management The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company’s definitive Proxy Statement for its February 15, 2001 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2000. The information concerning security ownership of management is set forth in the definitive Proxy Statement under the caption “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference. (c) Changes in Control None I T E M•13 Certain Relationships and Related Transactions The information required by this item is omitted pursuant to Instruction G of Form 10-K since the Company’s definitive Proxy Statement for its February 15, 2001 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 2000. The information regarding certain relationships and related transactions is set forth in the definitive Proxy Statement under the caption “Compensation Committee Interlocks and Insider Participation” and is incorporated herein by reference. Part IV I T E M•14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K (a) Financial Statement Schedules All financial statement schedules filed as part of this report are included in Item 8 of this Form 10-K and reference is made thereto. (b) Reports on Form 8-K None (c) Exhibits Exhibit Number Description of Exhibits 3(i) Articles of Incorporation: • Restated Certificate of Incorporation of National Fuel Gas Company dated September 21, 1998 (Exhibit 3.1, Form 10-K for fiscal year ended September 30, 1998 in File No. 1-3880) 3(ii) By-Laws: • National Fuel Gas Company By-Laws as amended on February 17, 2000 (Exhibit 3.1, Form 10-K for fiscal year ended June 30, 2000 in File No.1-3880) Instruments Defining the Rights of Security Holders, Including Indentures: Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 2(b) in File No. 2-51796) (4) • 90 • • • Third Supplemental Indenture dated as of December 1, 1982, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (for- merly Irving Trust Company) (Exhibit 4(a)(4) in File No. 33-49401) Tenth Supplemental Indenture dated as of February 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (for- merly Irving Trust Company) (Exhibit 4(a), Form 8-K dated February 14, 1992 in File No. 1-3880) Eleventh Supplemental Indenture dated as of May 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (for- merly Irving Trust Company) (Exhibit 4(b), Form 8-K dated February 14, 1992 in File No. 1-3880) NATIONAL FUEL GAS COMPANY • • • • • • • Twelfth Supplemental Indenture dated as of June 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4(c), Form 8-K dated June 18, 1992 in File No. 1-3880) Thirteenth Supplemental Indenture dated as of March 1, 1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (for- merly Irving Trust Company) (Exhibit 4(a)(14) in File No. 33-49401) Fourteenth Supplemental Indenture dated as of July 1, 1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (for- merly Irving Trust Company) (Exhibit 4.1, Form 10-K for fiscal year ended September 30, 1993 in File No. 1-3880) Fifteenth Supplemental Indenture dated as of September 1, 1996 to Indenture dated as of October 15, 1974, between the Company and The Bank of New York (formerly Irving Trust Company) (Exhibit 4.1, Form 10- K for fiscal year ended September 30, 1996 in File No. 1-3880) Indenture dated as of October 1, 1999, between the Company and The Bank of New York (Exhibit 4.1, Form 10-K for fiscal year ended September 30, 1999 in File No.1-3880) Officer’s Certificate Establishing Medium-Term Notes dated October 14, 1999 (Exhibit 4.2, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) Amended and Restated Rights Agreement, dated as of April 30, 1999, between National Fuel Gas Company and HSBC Bank USA (Exhibit 10.2, Form 10-Q for the quar- terly period ended March 31, 1999 in File No. 1-3880) (10) Material Contracts: (iii) Compensatory plans for officers: • • • • • • • • • Employment Agreement, dated September 17, 1981, with Bernard J. Kennedy (Exhibit 10.4, Form 10-K for fiscal year ended September 30, 1994 in File No. 1-3880) Tenth Amendment to Employment Agreement with Bernard J. Kennedy, effective September 1, 1999 (Exhibit 10.1, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) Agreement dated August 1, 1986, with Joseph P. Pawlowski (Exhibit 10.1, Form 10-K for fiscal year ended September 30,1997 in File No. 1-3880) Agreement dated August 1, 1986, with Gerald T. Wehrlin (Exhibit 10.2, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880) Form of Employment Continuation and Noncompetition Agreements, dated as of December 11, 1998, with Philip C. Ackerman, Walter E. DeForest, Joseph P. Pawlowski, Dennis J. Seeley, David F. Smith and Gerald T. Wehrlin (Exhibit 10.1, Form 10-Q for the quarterly period ended June 30, 1999 in File No. 1-3880) Severance Agreement, Release and Waiver dated March 27, 2000, between National Fuel Gas Supply Corporation and Richard Hare (Exhibit 10.2, Form 10-Q for the quar- terly period ended March 31, 2000) Form of Employment Continuation and Noncompetition Agreement, dated as of December 11, 1998, with James A. Beck (Exhibit 10.3, Form 10-Q for the quarterly period ended June 30, 1999 in File No. 1-3880) National Fuel Gas Company 1983 Incentive Stock Option Plan, as amended and restated through February 18, 1993 (Exhibit 10.2, Form 10-Q for the quarterly period ended March 31, 1993 in File No. 1-3880) National Fuel Gas Company 1984 Stock Plan, as amended and restated through February 18, 1993 (Exhibit 10.3, Form 10-Q for the quarterly period ended March 31, 1993 in File No. 1-3880) • • • • • • • • • • • • • • • • • • Amendment to the National Fuel Gas Company 1984 Stock Plan, dated December 11, 1996 (Exhibit 10.7, Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880) National Fuel Gas Company 1993 Award and Option Plan, dated February 18, 1993 (Exhibit 10.1, Form 10-Q for the quarterly period ended March 31, 1993 in File No. 1-3880) Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated October 27, 1995 (Exhibit 10.8, Form 10-K for fiscal year ended September 30, 1995 in File No. 1-3880) Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated December 11, 1996 (Exhibit 10.8, Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880) Amendment to National Fuel Gas Company 1993 Award and Option Plan, dated December 18, 1996 (Exhibit 10, Form 10-Q for the quarterly period ended December 31, 1996 in File No. 1-3880) Amended and Restated National Fuel Gas Company 1997 Award and Option Plan, as amended and restated through February 17, 2000 (Exhibit 10.1, Form 10-Q for the quarterly period ended March 31, 2000 in File No. 1-3880) National Fuel Gas Company Deferred Compensation Plan, as amended and restated through May 1, 1994 (Exhibit 10.7, Form 10-K for fiscal year ended September 30, 1994 in File No. 1-3880) Amendment to the National Fuel Gas Company Deferred Compensation Plan, dated September 19, 1996 (Exhibit 10.10, Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880) Amendment to the National Fuel Gas Company Deferred Compensation Plan, dated September 27, 1995 (Exhibit 10.9, Form 10-K for fiscal year ended September 30, 1995 in File No. 1-3880) National Fuel Gas Company Deferred Compensation Plan, as amended and restated through March 20, 1997 (Exhibit 10.3, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880) Amendment to National Fuel Gas Company Deferred Compensation Plan dated June 16, 1997 (Exhibit 10.4, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880) Amendment No. 2 to the National Fuel Gas Company Deferred Compensation Plan, dated March 13, 1998 (Exhibit 10.1, Form 10-K for fiscal year ended September 30, 1998 in File No. 1-3880) Amendment to the National Fuel Gas Company Deferred Compensation Plan, dated February 18, 1999 (Exhibit 10.1, Form 10-Q for the quarterly period ended March 31, 1999 in File No. 1-3880) National Fuel Gas Company Tophat Plan, effective March 20, 1997 (Exhibit 10, Form 10-Q for the quarterly period ended June 30, 1997 in File No. 1-3880) Amendment No. 1 to the National Fuel Gas Company Tophat Plan, dated April 6, 1998 (Exhibit 10.2, Form 10-K for fiscal year ended September 30, 1998 in File No. 1-3880) Amendment No. 2 to the National Fuel Gas Company Tophat Plan, dated December 10, 1998 (Exhibit 10.1, Form 10-Q for the quarterly period ended December 31, 1998 in File No. 1-3880) Death Benefits Agreement, dated August 28, 1991, with Bernard J. Kennedy (Exhibit 10-TT, Form 10-K for fiscal year ended September 30, 1991 in File No. 1-3880) Amendment to Death Benefit Agreement of August 28, 1991, with Bernard J. Kennedy, dated March 15, 1994 (Exhibit 10.11, Form 10-K for fiscal year ended September 30, 1995 in File No. 1-3880) 91 NATIONAL FUEL GAS COMPANY 92 • • • • • • • • • • • • • • • Amended and Restated Split Dollar Insurance Agreement, effective June 15, 2000 among National Fuel Gas Company, Bernard J. Kennedy, and Joseph B. Kennedy, as Trustee of the Trust under the Agreement dated January 9, 1998 (Exhibit 10.1, Form 10-Q for the quarterly period ended June 30, 2000 in File No. 1-3880) Contingent Benefit Agreement effective June 15, 2000 between National Fuel Gas Company and Bernard J. Kennedy (Exhibit 10.2, Form 10-Q for the quarterly period ended June 30, 2000 in File No. 1-3880) Amended and Restated Split Dollar Insurance and Death Benefit Agreement dated September 17, 1997 with Philip C. Ackerman (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880) Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit Agreement by and Between National Fuel Gas Company and Philip C. Ackerman, dated March 23, 1999 (Exhibit 10.3, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) Amended and Restated Split Dollar Insurance and Death Benefit Agreement dated September 15, 1997 with Joseph P. Pawlowski (Exhibit 10.7, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880) Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit Agreement by and Between National Fuel Gas Company and Joseph P. Pawlowski, dated March 23, 1999 (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) Second Amended and Restated Split Dollar Insurance Agreement dated June 15, 1999 with Gerald T. Wehrlin (Exhibit 10.6, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) Amended and Restated Split Dollar Insurance and Death Benefit Agreement dated September 15, 1997 with Walter E. DeForest (Exhibit 10.7, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit Agreement by and Between National Fuel Gas Company and Walter E. DeForest, dated March 29, 1999 (Exhibit 10.8, Form 10- K for fiscal year ended September 30, 1999 in File No. 1-3880) Amended and Restated Split Dollar Insurance and Death Benefit Agreement dated September 15, 1997 with Dennis J. Seeley (Exhibit 10.9, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) Amendment Number 1 to Amended and Restated Split Dollar Insurance and Death Benefit Agreement by and Between National Fuel Gas Company and Dennis J. Seeley, dated March 29, 1999 (Exhibit 10.10, Form 10-K for fiscal year ended September 30, 1999 in File No. 1- 3880) Split Dollar Insurance and Death Benefit Agreement dated September 15, 1997 with Bruce H. Hale (Exhibit 10.11, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) Amendment Number 1 to Split Dollar Insurance and Death Benefit Agreement by and Between National Fuel Gas Company and Bruce H. Hale, dated March 29, 1999 (Exhibit 10.12, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) Split Dollar Insurance and Death Benefit Agreement dated September 15, 1997 with David F. Smith (Exhibit 10.13, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) Amendment Number 1 to Split Dollar Insurance and Death Benefit Agreement by and Between National Fuel Gas Company and David F. Smith, dated March 29, 1999 (Exhibit 10.14, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) • • • • • • • • • • National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan as amended and restated through November 1, 1995 (Exhibit 10.10, Form 10-K for fiscal year ended September 30, 1995 in File No. 1-3880) National Fuel Gas Company and Participating Subsidiaries 1996 Executive Retirement Plan Trust Agreement (II) dated May 10, 1996 (Exhibit 10.13, Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880) Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan dated September 18, 1997 (Exhibit 10.9, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880) Amendments to the National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan dated December 10, 1998 (Exhibit 10.2, Form 10-Q for the quarterly period ended December 31, 1998 in File No. 1-3880) Amendments to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan effec- tive September 16, 1999 (Exhibit 10.15, Form 10-K for fiscal year ended September 30, 1999 in File No. 1-3880) Administrative Rules with Respect to at Risk Awards under the 1993 Award and Option Plan (Exhibit 10.14, Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880) Administrative Rules with Respect to at Risk Awards under the 1997 Award and Option Plan (Exhibit A, Definitive Proxy Statement, Schedule 14(A) filed January 14, 2000 in File No. 1-3880) Administrative Rules of the Compensation Committee of the Board of Directors of National Fuel Gas Company, as amended and restated, effective December 10, 1998 (Exhibit 10.3, Form 10-Q for the quarterly period ended December 31, 1998 in File No. 1-3880) Excerpts of Minutes from the National Fuel Gas Company Board of Directors Meeting of February 20, 1997 regarding the Retirement Benefits for Bernard J. Kennedy (Exhibit 10.10, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880) Excerpts of Minutes from the National Fuel Gas Company Board of Directors Meeting of March 20, 1997 regarding the Retainer Policy for Non-Employee Directors (Exhibit 10.11, Form 10-K for fiscal year ended September 30, 1997 in File No. 1-3880) (12) Computation of Ratio of Earnings to Fixed Charges (21) Subsidiaries of the Registrant: See Item 1 of Part I of this Annual Report on Form 10-K (23) Consents of Experts: 23.1 Consent of Ralph E. Davis Associates, Inc. 23.2 Consent of Independent Accountants 23.3 Consent of McDaniel & Associates Consultants Ltd. (27) Financial Data Schedules: 27.1 Financial Data Schedule for the Twelve Months Ended September 30, 2000 27.2 Restated Financial Data Schedule for the Twelve Months Ended September 30, 1999 (99) Additional Exhibits: 99.1 Report of Ralph E. Davis Associates, Inc. 99.2 Report of McDaniel & Associates Consultants Ltd. All other exhibits are omitted because they are not applicable or the required information is shown elsewhere in this Annual Report on Form 10-K. • Incorporated herein by reference as indicated. NATIONAL FUEL GAS COMPANY 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. National Fuel Gas Company (Registrant) By/s/ B. J. Kennedy B. J. Kennedy Chairman of the Board and Chief Executive Officer Date: December 7, 2000 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 dates indicated. SIGNATURE / TITLE /s/ B. J. Kennedy B. J. Kennedy Chairman of the Board, Chief Executive Officer and Director Date: December 7, 2000 /s/ P. C. Ackerman P. C. Ackerman President, Principal Financial Officer and Director Date: December 7, 2000 /s/ R. T. Brady R. T. Brady Director Date: December 7, 2000 /s/ J. V. Glynn J. V. Glynn Director Date: December 7, 2000 /s/ W. J. Hill W. J. Hill Director Date: December 7, 2000 SIGNATURE / TITLE /s/ B. S. Lee B. S. Lee Director Date: December 7, 2000 /s/ E. T. Mann E. T. Mann Director Date: December 7, 2000 /s/ G. L. Mazanec G. L. Mazanec Director Date: December 7, 2000 /s/ J. F. Riordan J. F. Riordan Director Date: December 7, 2000 /s/ J. P. Pawlowski J. P. Pawlowski Treasurer and Principal Accounting Officer Date: December 7, 2000 93 NATIONAL FUEL GAS COMPANY National Fuel Gas Company Officers Bernard J. Kennedy Chairman of the Board and Chief Executive Officer Philip C. Ackerman President Joseph P. Pawlowski Treasurer Gerald T. Wehrlin Controller Anna Marie Cellino Secretary National Fuel Gas Distribution Corporation Officers of Principal Subsidiaries Bernard J. Kennedy Chairman of the Board David F. Smith President Walter E. DeForest Senior Vice President Dennis J. Seeley Senior Vice President Gerald T. Wehrlin Senior Vice President Carl M. Carlotti Vice President Joseph P. Pawlowski Senior Vice President and Treasurer Anna Marie Cellino Vice President and Secretary National Fuel Gas Supply Corporation Bernard J. Kennedy Chairman of the Board Dennis J. Seeley President Philip C. Ackerman Executive Vice President Bruce H. Hale Senior Vice President David F. Smith Senior Vice President John R. Pustulka Vice President Seneca Resources Corporation Bernard J. Kennedy Chairman of the Board William M. Petmecky Senior Vice President and Secretary James A. Beck President Thomas L. Atkins Controller Barry L. McMahan Senior Vice President Don A. Brown Vice President Robert T. Evans Vice President Gil E. Klefstad Vice President National Fuel Resources, Inc. William M. Petmecky Secretary and Treasurer James D. Ramsdell Vice President Ronald J. Tanski Vice President and Controller William A. Ross Vice President Joseph P. Pawlowski Secretary and Treasurer John F. McKnight Vice President Emmett E. Wassell Vice President Calvin H. Friedrich Treasurer Highland Forest Resources, Inc. James A. Beck President William M. Petmecky Secretary Calvin H. Friedrich Treasurer Horizon Energy Development, Inc. Philip C. Ackerman President Bruce H. Hale Vice President Gerald T. Wehrlin Vice President Ronald J. Tanski Secretary and Treasurer 94 NATIONAL FUEL GAS COMPANY Directors Bernard J. Kennedy ∆ ∆ Chairman of the Board and Chief Executive Officer. Board member since 1978. Chairman of the Board of Associated Electric & Gas Insurance Services Limited. Director of the Gas Technology Institute, Interstate Natural Gas Association of America, HSBC Bank USA, and Merchants Mutual Insurance Company. Philip C. Ackerman President of National Fuel Gas Company since July 1999. President of certain subsidiaries of the Company. Board member since 1994. Robert T. Brady ∆ † Chairman, President and Chief Executive Officer of Moog Inc., a manufacturer of motion control systems and components. Board member since 1995. Director of Acme Electric Corporation, Astronics Corporation, M&T Bank Corporation, M&T Bank and Seneca Foods Corporation. James V. Glynn* President of Maid of the Mist Corporation, which offers scenic boat tours of the American and Canadian waterfalls, Niagara Falls, New York. Board member since 1997. Director of M&T Bank Corporation, M&T Bank, and Buffalo Niagara Partnership. Chairman of Niagara University Board of Trustees. ∆* William J. Hill Retired President of National Fuel Gas Distribution Corporation. Board member since 1995. Director of National Fuel Gas Distribution Corporation and Reed Manufacturing Company. Bernard S. Lee, PhD** Former President of the Gas Technology Institute, a not-for-profit research and educational institu- tion, Des Plaines, Illinois. Board member since 1994. Director of NUI Corporation and Peerless Manufacturing Company. Eugene T. Mann ∆ † Retired Executive Vice President of Fleet Financial Group, a diversified financial services company, Providence, Rhode Island. Board member since 1993. George L. Mazanec††∆ Former Vice Chairman of PanEnergy Corporation, a diversified energy company, and advisor to the Chief Operating Officer of Duke Energy Corporation. Board member since 1996. Director of the Northern Trust Bank of Texas, NA, Westcoast Energy Inc., and Associated Electric & Gas Insurance Services Limited. Chairman of the Management Committee of Maritimes & Northeast Pipeline, L.L.C. John F. Riordan* President and Chief Executive Officer since April 2000 of the Gas Technology Institute, Des Plaines, Illinois. Board member since July 1, 2000. Director of the University at Buffalo School of Management and the Oral and Maxillofacial Surgery Foundation. * Member of Audit Committee ** Chairman, Audit Committee † Member of Compensation Committee † † Chairman, Compensation Committee ∆ Member of Executive Committee ∆ ∆ Chairman, Executive Committee 95 NATIONAL FUEL GAS COMPANY 96 Glossary bbl barrel Bcf Billion cubic feet Bcf (or Mcf) Equivalent The total heat value (Btu) of natural gas and oil expressed as a volume of natural gas. National Fuel uses a conversion formula of 1 barrel of oil = 6 Mcf of natural gas. Blackstart Energizing a grid to restore power. Board Foot A measure of lumber and/or timber equal to 12 inches in length by 12 inches in width by one inch in thickness. Cyclic Steaming A thermal recovery method involving the injection of steam into a producing well for a predetermined length of time, after which the well is returned to productive status. Used in a heavy oil reservoir to reduce viscosity and increase recovery of the oil. Degree Day A measure of the coldness of the weather experi- enced, based on the extent to which the daily average tempera- ture falls below a reference temperature, usually 65 degrees Fahrenheit. Derivative A contract, as an option or futures contract, whose value depends on the value of the securities, commodities, etc. that form the basis of the contract. District Heating Plant A facility designed to produce steam or hot water for distribution to end users. Normally located in an urban area. Dth Dekatherm -one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas. FERC Federal Energy Regulatory Commission Firm Transportation and/or Storage The transportation and/or storage service that a supplier of such service is obligated by contract to provide. Forest Inventory A compilation of the physical characteristics of the forest and land that may include timber quantity and size, site quality, relative density, forest health, and the geographic location of the described units to facilitate the management of the forest resource. Gigajoule One billion joules. A “joule” is a unit of energy. Hedging A method of minimizing the impact of price, interest rate, and/or foreign currency exchange rate changes. Hub Location where pipelines intersect enabling the trading, transportation, storage, exchange and lending of natural gas. Hydraulic Fracture A mechanical method of increasing the permeability of rock, and thus increasing the amount of oil or gas produced from it. The method employs hydraulic pressure to fracture the rock. It is extensively employed on limestone formations. Interruptible Transportation and/or Storage The transporta- tion and/or storage service that, in accordance with contractual arrangements, can be interrupted by the supplier of such service. Island Performance The capability of operating in isolation from the local distribution grid during an electric outage. Kiln An oven, furnace, or heated enclosure used for processing a substance by burning, firing, or drying. Kilowatt (kW) A unit of electrical power equal to one thousand watts. Mbbl Thousand barrels Mcf Thousand cubic feet MDth Thousand dekatherms Megawatt One million watts. A “watt” is a unit of electrical power. Megawatt hour A unit of electrical energy which equals one megawatt of power used for one hour. Microturbine A small-scale gas turbine, typically producing less than 1,000 kilowatts (kW) of power. The technology employed by microturbines is the same as that of jet engines, using rotating power to drive electric generators that produce electricity. MMcf Million cubic feet MMcfe Million cubic feet equivalent (1 barrel of oil = 6 Mcf of gas) NYMEX New York Mercantile Exchange. An exchange which maintains a futures market for crude oil and natural gas. NYPSC State of New York Public Service Commission Open Access Transportation The transportation of natural gas by a pipeline or utility upon request. PaPUC Pennsylvania Public Utility Commission Reserves Estimated volumes of oil, gas or other minerals that can be recovered from deposits in the earth with reasonable certainty. Solution Gas Gas that is dissolved in oil in the reservoir under pressure. Spot Gas Purchases The purchase of natural gas on a short-term basis usually at a lower cost than long-term pipeline contracts. Stranded Costs Costs associated with facilities or contracts that, because of restructuring, may not be directly recoverable from customers. Timber Cruise A compilation of the timber quantity by species, size, and quality. May be complete or a representative sample. Transportation Gas The movement of gas for third parties through pipeline facilities for a fee. Unbundled Service The separation of services, with rates charged that reflect the cost of the selected service. Underground Storage The injection of large quantities of natural gas into underground rock formations for storage during periods of low market demand and withdrawal during periods of high market demand. Viscosity One of the physical properties of a liquid, namely, its ability to flow. It is expressed inversely; in other words, the less viscous the fluid the greater its mobility. The viscosity of oil in a reservoir affects the rate of recovery. Weather Normalization A clause in utility rates which adjusts customer costs to reflect normal temperatures. If temperatures during the measured period are warmer than normal, customers receive a surcharge. If temperatures during the measured period are colder than normal, customers receive a credit. Weighted Average Price A price computed by averaging together the cost of each unit. Investor Information Common Stock Transfer Agent and Registrar* Investor Relations Mellon Investor Services LLC P.O. Box 3316 South Hackensack, N.J. 07606-1916 Tel. (800) 648-8166 or Web site at http://www.chasemellon.com *Change-of-address notices and inquiries about dividends should be sent to the Transfer Agent at address shown. Stock Listing New York Stock Exchange (Stock Symbol: NFG) National Fuel Direct Stock Purchase and Dividend Reinvestment Plan National Fuel offers a simple, cost-effective method for purchasing shares of National Fuel stock directly from the Company. A Prospectus which includes details of the Plan can be obtained by calling, writing or e-mailing Mellon Investor Services LLC, the agent for the Plan, at: Mellon Investor Services LLC Dividend Reinvestment Department P.O. Box 3336 South Hackensack, N.J. 07606-1936 Tel. (800) 648-8166 E-mail: shrrelations@chasemellon.com Trustee for Debentures The Bank of New York 101 Barclay Street New York, N.Y. 10286 Independent Accountants PricewaterhouseCoopers LLP 3600 HSBC Center Buffalo, N.Y. 14203 Annual Meeting The Annual Meeting of Shareholders will be held at 10 a.m. (local time) on Thursday, February 15, 2001, at The Houstonian Hotel, Club & Spa, 111 North Post Oak Lane, Houston, Texas 77024. Formal notice of the meeting, proxy statement and proxy will be mailed to shareholders of record as of December 18, 2000. Investors or financial analysts desiring information should contact: Joseph P. Pawlowski Treasurer Tel. (716) 857-6904 Margaret M. Suto Director, Investor Relations Tel. (716) 857-6987 or E-mail: sutom@natfuel.com National Fuel Gas Company 10 Lafayette Square Buffalo, N.Y. 14203 Additional Shareholder Reports Additional copies of this report and the Financial and Statistical Supplement to the 2000 Annual Report can be obtained without charge by writing to: Anna Marie Cellino Corporate Secretary National Fuel Gas Company 10 Lafayette Square Buffalo, N.Y. 14203 Tel. (716) 857-7858 This Annual Report and the statements contained herein are submitted for the general information of shareholders and employees of the Company and are not intended to induce any sale or purchase of securities or to be used in connection therewith. For up-to-date information we have two sources for your use. You may call 1-800-334-2188 at any time to receive National Fuel’s current stock price and trade volume or to hear the latest news releases. You may also have news releases faxed or mailed to you. National Fuel has an Internet Web site at http://www.nationalfuelgas.com. You may sign-up there to automatically receive news releases by e-mail. Simply go to the News & Info section and subscribe. Printed on Recyclable Paper with Soybean Inks 97 National Fuel Gas Company 10 Lafayette Square Buffalo, NY 14203 (716) 857-7000 www.nationalfuelgas.com
Continue reading text version or see original annual report in PDF format above