National Fuel Gas Company 9 9 9 1 Annual Report and Form 10-K C O R P O R A T E P R O F I L E National Fuel Gas Company, incorporated in 1902, is a diversified energy company with its headquarters in Buffalo, New York. The Company’s $2.8 billion in assets is distributed among six business segments: Exploration and Production, Pipeline and Storage, Utility, International, Energy Marketing and Timber. National Fuel’s history dates to the earliest days of the natural gas and oil industry in the United States, and the Company has been responsible for many industry firsts. As we begin the new century, the Company continues to be managed in the same innovative and entrepreneurial spirit. EXPLORATION AND PIPELINE AND PRODUCTION Seneca Resources Corporation explores for, develops and pur- chases natural gas and oil reserves in the Gulf Coast Region of Texas and Louisiana, the Appalachian Region, the Rocky Mountain Region and in California. Currently, Seneca’s exploration emphasis is centered around the Gulf Coast in offshore waters, while develop- ment drilling has expanded in California. STORAGE National Fuel Gas Supply Corporation provides interstate natural gas trans- portation and storage for affiliated and non- affiliated companies through an inte- grated 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 oper- ator of four others. UTILITY National Fuel Gas Distribution Corporation sells or transports natural gas to over 733,000 cus- tomers 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. INTERNATIONAL Horizon Energy Development, Inc. engages in foreign energy projects through the invest- ments of its indirect subsidiaries as the sole or substantial owner of various business entities. One of its wholly owned entities has a majority ownership in three district heating and power generation compa- nies located in the Czech Republic. ENERGY MARKETING National Fuel Resources, Inc. is engaged in the mar- keting and brokerage of natural gas and electricity and the performance of energy management services for indus- trial, commercial, public authority and residential end-users throughout the northeast United States. TIMBER Highland Land & Minerals, 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. Highlights 1 At A Glance 2 Letter to Shareholders 4 Business Segment Discussion 7 Form 10-K 17 Officers and Directors 94 Glossary 96 Investor Information 97 C O N T E N T S H I G H L I G H T S Year Ended September 30 1 9 9 9 1 9 9 8 1 9 9 7 1 9 9 6 1 9 9 5 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 $1,263,274 $ 115,037 $1,248,000 23,188 $ $1,265,812 $ 114,688 $1,208,017 $ 104,671 $ 975,496 75,894 $ $ 115,037 12.6% $ 111,418(1) 2.6% $ 114,688 13.0% $ 104,671 12.6% $ 75,894 9.6% 12.6% 11.9%(1) 13.0% 12.6% 9.6% $ 2.98 $ 2.95 $ 2.98 $ 2.95 $ 1.82 $ 1.86 $24.19 38,837,499 $ 0.61 $ 0.60 $ 2.91(1) $ 2.88(1) $ 1.76 $ 1.80 $23.14 38,468,795 38,663,981 39,041,728 60,663 38,316,397 38,703,526 62,741 $ 50 $ 37 1⁄2 $473⁄16 $49 1⁄8 $39 5⁄8 $47 $ 3.01 $ 2.98 $ 3.01 $ 2.98 $ 1.70 $ 1.74 $23.94 38,165,888 38,083,514 38,440,018 59,456 $45 7⁄16 $36 5⁄8 $44 $ 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 $28 1⁄2 $36 3⁄4 $ 2.03 $ 2.03 $ 2.03 $ 2.03 $ 1.59 $ 1.62 $21.39 37,434,363 37,396,875 37,476,534 43,531 $30 3⁄4 $25 $28 3⁄4 Net Cash Provided by Operating Activities (Thousands) Total Assets (Thousands) Expenditures for Long-Lived Assets (Thousands) $ 271,890 $2,842,586 $ 269,913 $ 252,978 $2,684,459 $ 510,652 $ 294,662 $2,267,331 $ 248,311 $ 168,469 $2,149,772 $ 174,502 $ 174,361 $2,036,823 $ 182,826 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 30 101,675 64,284 108,599 60,386 127,501 57,875 132,742 58,218 116,297 52,830 308,303 313,048 300,302 325,006 290,739 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 34,454 26,453 21,024 10,047,042 1,138,980 693,023 7,116,776 763,848 704,217 41,515 3,807(2) 28,224 3,944(2) 262,615 — 731,034 2,013 2,524 38,767 1,742 49,219 207,082 25,749 361,576 20,232 36,652 — 20,942 739 25,376 221,459 22,865 358,649 18,841 — — 732,493 729,945 1,733 2,843 1,528 2,925 (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 1,406 and 1,390 international employees at September 30, 1999 and 1998, respectively. N a t i o n a l F u e l G a s C o m p a n y 1 At A Glance E X P L O R AT I O N A N D P R O D U C T I O N WY CA MI NY PA Seneca Resources TX LA IN 1999 OUTLOOK* • Net income of $7.1 million contributed 6% of total Company earnings. • Drilled a total of 118 wells with 91% success rate; 95 successful wells were in California. • Increase total production in 2000 by over 20% to 74.4 Bcf equivalent. • 2000 capital budget of $112.2 million, excluding acquisitions; 84% targeted for Gulf Region. • 40 development wells planned in • Record production of 61.3 Bcf equiv- California for 2000. alent. • Total reserves increased 7% to 776 Bcf equivalent. • Continue cost containment policies to be low cost operator and producer. P I P E L I N E A N D S T O R A G E IN 1999 OUTLOOK* • Net income of $39.8 million was • Awaiting FERC final certification on nearly 35% of total Company earnings. Independence Pipeline project. • Independence Pipeline project • Anticipate expanding capacity incre- continues on track; received final Environmental Impact Statement in November 1999 from Federal Energy Regulatory Commission (FERC). • Ellisburg, Pennsylvania compressor station capacity increased 62 MMcf per day. mentally in the Niagara Spur as demand increases. • Seek other opportunities to expand into new geographic areas. Lake Ontario NY VT 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 T R A N S M I S S I O N C O R P. Buffalo C N G Lake Erie TENNESSEE GAS PIPELINE COMPANY MA CT T R A N S M I S S I O N C O R P. C O L U M B I A G A S PA 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. P . R O E C E L I N S P I P A G NJ TRA NSCO NTINENTAL Supply Corporation: Storage Areas System Pipelines U T I L I T Y IN 1999 OUTLOOK* • Net income of $56.9 million • Continue to work with the NYPSC contributed 49% of total Company earnings. and the PaPUC on defining industry restructuring. • Completed first year of two year • Explore value added services and rate plan effective October 1, 1998 in New York. products for entire Utility customer base. • Traditional customer service perfor- • Continue emphasis on strengths: mance measures improved or remained at historically high levels. • Customer choice programs now available to all customers in New York and Pennsylvania. cost containment, superior customer service, and a managed transition to competition. Lake Ontario NY CANADA Buffalo Lake Erie Erie PA Distribution Corporation Service Area 2 NET INCOME by Segment 4% 2% 2% 2% 6% 3 5 % 49% Total: $115.0 million NET PLANT by Segment 4% 8% 29% 39% 20% Total: $2.4 billion Utility Pipeline and Storage Exploration and Production International Energy Marketing Timber All Other and Corporate BASIC EARNINGS PER COMMON SHARE Dollars Per Common Share 3.01 2.91 (1) 2.98 2.78 2.03 .61 9 5 9 6 9 7 9 8 9 9 (1) Excludes special items for impairment of oil and gas producing assets and for cumulative effect of change in accounting. I N T E R N AT I O N A L G E R M A N Y SCT PSZT P O L A N D • Net income of $2.3 million was 78% IN 1999 higher than 1998 earnings. • Net plant now $203.5 million. C Z E C H R E P U B L I C OUTLOOK* • Merger of SCT and PSZT on target for 2000. • Prague base allows us to look at opportunities within Eastern Europe. S L O VA K I A A U S T R I A Horizon Energy E N E R G Y M A R K E T I N G IN 1999 • Net income of $2.1 million was 161% higher than 1998. • Residential customer base more than tripled; natural gas volumes increased 30% to 34.5 Bcf. OUTLOOK* • Pursue opportunities from electric and gas industry restructuring. Lake Erie NY PA Seneca Acreage PennzEnergy Acreage Acquired Sawmills Lake Ontario NY CANADA Lake Erie PA NJ National Fuel Resources T I M B E R IN 1999 • Net income increased nearly 151% to $4.8 million, or 4% of total Company earnings. • Acquired from PennzEnergy over 36,000 acres of high-quality timber contiguous to our holdings in Pennsylvania. OUTLOOK* • Complete timber inventory to effec- tively evaluate our timber assets. 3 L E T T E R T O S H A R E H O L D E R S In 1999, our earnings per share of $2.98 not only exceeded last year’s earnings of $2.91 (exclusive of the oil and gas impairment and the cumulative effect of the change in accounting methods), but more importantly, it was our second best year ever. The fact that we came PHILIP C. ACKERMAN President BERNARD J. KENNEDY Chairman of the Board and Chief Executive Officer within one percent of our record-breaking performance in 1997 of $3.01 per share, despite some serious handicaps, demonstrates the strength of your Company and the tremendous potential that we feel could be realized in a year when conditions are more favorable.* 4 While 1999 was not “the worst of times,” we began about air quality and the environmental impact of using the first half of the year with three rather challenging coal and oil, and the age of many of this country’s coal and obstacles: first, a winter that was warmer than normal not nuclear power plants.* As the increase in consumption only in our Utility service areas, but also in Europe; comes to pass, we believe your Company is prepared to second, extremely low oil and gas prices which reduced the capitalize on this opportunity.* An increase in demand for profitability of our Exploration and Production operations; natural gas should also lead to an increase in prices bene- and third, as part of a two year settlement with the New fiting our Exploration and Production segment with its York Public Service Commission (NYPSC), a base rate substantial reserves and undeveloped acreage.* reduction and agreement to fund the costs of restructur- As gas moves to northeast markets from either the ing. However, with the dedicated efforts of our employees Gulf Coast or the Canadian Rockies, the configuration of and some recent relief in commodity pricing, “the best of our country’s pipeline system is such that the obvious paths times” came within our grasp by the closing months of for the gas is through our service territory either south of the year. Lake Erie on the proposed Independence Pipeline, of With today’s strong oil prices coupled with an which we are a 1/3 owner, or north across the Niagara expected 20% increase in our production for 2000, we River and down our system.* The increased gas flow should anticipate record earnings in the coming year.* While the also provide expansion opportunities for our storage ser- market price of our stock closed at $47 3/16 at fiscal year vices and Leidy Hub.* In addition, increased use of gas on end, it reached a new high in November of $5215/16. our system could benefit our Utility segment and offer addi- Further, although our expectations in 2000 center around tional potential for our Energy Marketing segment.* our Exploration and Production segment, we think that Meanwhile, on a state level, deregulation has contin- prospects in general have never been better for your ued to move ahead in both Pennsylvania and New York. Company.* Pennsylvania revoked the gross receipts tax on gas utility While opinions may vary about magnitude and timing, sales and passed legislation to implement its restructuring knowledgeable authorities agree that consumption of plan. Although New York has not yet completed its restruc- natural gas for power generation will increase because of turing plans, the NYPSC is currently working to transform increasing demands for electric power, growing concerns its “vision” statement on deregulation into reality.* Notes: 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. This document contains “forward- looking statements” as defined by the Private Securities Litigation Reform Act of 1995. Forward-looking statements, including those desig- nated by a “*”, should be read with the cautionary statements and impor- tant factors included in this Annual Report on Form 10-K at Item 7, under the heading “Safe Harbor for Forward-Looking Statements.” ANNUAL DIVIDEND RATE AT YEAR END RETURN ON AVERAGE COMMON EQUITY Dollars Per Common Share Percent 1.86 13.0 12.6 12.6 11.9 (1) 1.34 9.6 2.6 (1) Excludes special items for impairment of oil and gas producing assets and for cumulative effect of change in accounting. 8 9 9 1 9 3 9 5 9 7 9 9 9 5 9 6 9 7 9 8 9 9 5 Paradoxically, despite the slower pace of its deregulation was decided that in 1999 our dividend would be increased initiative, opportunities appear greater for marketers in again. In June your Board of Directors raised the dividend New York where residential and small commercial cus- over 3%, or $.06 per share, to $1.86 on an annual basis. tomers of the Utility have turned to gas marketers at a rate This 29th consecutive annual increase also marks 97 years of over 1,000 per week during the past several months.* of uninterrupted dividend payments, a record of which few Our Energy Marketing segment has been one of the fastest companies on the New York Stock Exchange can boast. growing marketers in the State and has added as its sales During the past 25 years we have grown your customers many of those former Utility customers who Company from a local distribution company to one which have switched to transportation. reaches the breadth and depth of this great country, from During the year, three particular management changes our Niagara import station on the north, south to the Gulf were made to assist in the growth of the Company. Philip Coast, west to our California operations, and back east to C. Ackerman was elected President of National Fuel Gas Leidy Hub. We have also expanded internationally with our Company, David F. Smith was elected to replace Phil as operations in the Czech Republic. This year, our Company- President of National Fuel Gas Distribution Corporation wide capital expenditures including acquisitions and other (Distribution Corporation) and Donna L. DeCarolis was investments was $269.9 million; in 2000, our planned appointed Assistant Vice President of Distribution capital budget is $211.0 million, excluding acquisitions and Corporation. Phil had been involved for many years in the other investments.* nonregulated aspects of our business before he became Now, on the following pages, a senior officer from President of the Utility, and his new position will permit each of the Company’s reporting segments will tell you an integrated approach to expanding the entire Company.* about the significant accomplishments of that segment’s Dave has been with the Utility for 21 years and led the operations, and how he envisions that segment’s participa- Company’s efforts in the Pennsylvania restructuring collab- tion in this changing environment. orative. Donna has been assigned the specific task of Emerson once said, “Nothing great was ever achieved seeking growth opportunities for the Utility. without enthusiasm.” We cannot hide our enthusiasm and Following 28 consecutive years of increased dividends confidence that the solid, fundamental strength of and, with 1999 being another year of solid performance, it National Fuel Gas Company, together with natural gas’s FISCAL 1999 WEATHER Percent Colder (Warmer) 4.5 4.0 Than Last Year R E D L O C R E M R A W Than Normal OIL AND GAS PRICES Weighted Average After Hedging Dollars 18.01 17.95 15.86 13.03 12.96 (9.8) (9.9) 2.01 2.11 2.18 2.27 2.24 9 5 9 6 9 7 9 8 9 9 6 Buffalo, New York Erie, Pennsylvania Gas (per Mcf) Oil (per bbl) expanding role in the national energy equation, will help us build an even bigger and more profitable Company in the 21st century.* Bernard J. Kennedy Chairman of the Board and Chief Executive Officer Philip C. Ackerman President December 9, 1999 Geologists and geophysicists use computer technology to inter- pret three dimensional (3-D) seismic data in order to recom- mend prospective oil and gas drilling sites. Pictured here: Scott Gorham and Gerald Langille of Seneca’s Houston office. JAMES A. BECK President, Seneca Resources Corporation In the Gulf Coast, our successful off- shore exploration program continued. The most significant of these was ... Vermilion 253 where the first well had over 900 feet of oil and gas pay sands. Exploration and Production If this discussion had taken place in March, increased 17% from 1998 levels to 61.3 Bcf six months into 1999, the tone and message equivalent. A total of 118 wells were drilled would have been considerably different. Oil this year, and our team, aided by 3-D seismic prices were excessively low at $9.03 per bbl technology achieved a 91% success rate. We and natural gas prices of $1.92 per Mcf were replaced 187% of 1999 production with new dropping significantly because of record reserves from our exploration program, and storage volumes resulting mostly from a total reserves increased 7% in 1999 to 776 warmer than normal winter. This segment Bcf equivalent. had only contributed about $.01 per share to Performance improvements in our the Company’s earnings. California operations were truly impressive in What a difference six months makes! By 1999. After completing our three acquisitions the end of 1999 oil prices were moving in 1998, initial operating costs were nearly toward $25.00 per bbl and natural gas prices $6.00 per bbl of oil. At the end of 1999, increased to approximately $2.80 per Mcf. those costs were reduced to $4.07 per bbl . This segment’s earnings for 1999 of $7.1 Production had also significantly improved, million, or $.18 per share, contributed 6% of primarily due to a 95-well drilling program Company earnings, and we also finished the completed this year. At the end of 1999, daily year with a stellar production record. Total oil production had increased 17% from initial revenue this year was $147.0 million which production to 7,333 barrels per day. was 18% higher than 1998. Production 7 These pumping units are part of the heavy oil operation on Seneca’s Cherokee property at the Midway-Sunset Field. In 1999, Seneca drilled 51 wells at this site, which is located in California’s San Joaquin Basin. untapped opportunity.* However, the rela- tively low reserves per well and the long lives of the wells mean that we have to be con- vinced that gas prices would reach a sustain- able $3.00 per Mcf before we will commence large scale development.* Total production for Seneca for 2000 is expected to increase over 20% to 74.4 Bcf equivalent in a ratio of approximately 64% gas and 36% oil, and nearly 60% of this pro- duction is locked in through financial hedges.* Capital spending, exclusive of acqui- sitions, is anticipated to be $112.2 million with approximately 84% targeted for the Gulf Coast Region and the remainder for an addi- tional 40 development well program which has begun in our West Coast operations.* Recommendations from analysis of 3-D seismic data are carefully reviewed and evaluated. Pictured here: Seneca Houston personnel Linda Holmberg and John McKnight. In the Gulf Coast, our successful offshore Although 2000 could be as volatile as exploration program continued. New discover- 1999, we expect it to present many opportuni- ies at Vermilion 309, Vermilion 253, West ties as consolidation, strategic selling and Delta 78, High Island 365, and Galveston asset monetization continue in the explo- 225 contributed to the reserve replacement ration and production sector.* The manage- discussed above. The most significant of ment and employees of Seneca will concen- these was the announced discovery at trate on continuing our success in reducing Vermilion 253 where the first well had over production costs, enhancing reserve replace- 900 feet of oil and gas pay sands. Production ment and growing your Company through platforms and facilities are being installed, the drill bit and through acquisitions.* and we anticipate production to begin in late Seneca is prepared to take advantage of these Spring 2000.* Drilling will continue on both opportunities.* Vermilion 253 and 309 in 2000 with more production expected to be placed on line from these blocks.* Cost controls and an extremely efficient operation helped make us one of the lowest cost operators in the Appalachian region. The nearly 450,000 acres controlled by Seneca Resources Corporation (Seneca) in Pennsylvania and New York are a potential PROVED DEVELOPED AND UNDEVELOPED RESERVES In Bcf Equivalent OIL AND GAS PRODUCTION In Bcf Equivalent 775.7 724.6 61.3 49.2 50.0 52.2 358.7 361.6 340.3 25.4 9 5 9 6 9 7 9 8 9 9 9 5 9 6 9 7 9 8 9 9 Oil Gas Oil Gas 8 Timber The Timber segment is an increasingly impor- tant source of earnings.* This year’s earnings of $4.8 million, or $.12 per share, increased nearly 151% from 1998. This past July we acquired approximately 36,300 acres of land, timber and minerals from PennzEnergy Company for approxi- mately $47.0 million. This property is largely quality timber acreage located within the “cherry corridor” of Pennsylvania. Presently, we are conducting a timber inventory, or “cruise,” of all our holdings in order to better optimize the value of our timber assets. Many of our trees are nearing their economic maturity and detailed infor- mation is required to plan the most efficient realization of this value. We presently esti- mate that we own over 400 million board feet of hardwood timber, consisting mostly of cherry, maple and oak. Even after the cruise is completed and our plans are developed, it is likely that the maximum level of produc- tion will not be achieved for many years because of the sheer physical magnitude of carefully dealing with over 140,000 acres.* However, in the interim, we expect to sell certain noncore portions of our holdings in order to reduce debt.* Gregory Ochs operates the edger at the Marienville, Pennsylvania sawmill. The four sawmills owned by the Timber segment sold approximately 21.1 million board feet of logs and lumber this year. Right, Much of the timber har- vested is taken from the 140,000 acres owned by Seneca Resources. TIMBER PRODUCTION Board Feet in Millions 21.1 14.6 9.8 6.6 6.4 9 5 9 6 9 7 9 8 9 9 9 This year National Fuel Gas Supply Corporation replaced 14,000 feet of Line K, a major supply line which runs from Clarion, Pennsylvania to Buffalo, New York. Here, a welding crew works on a section of the new 20-inch steel pipe. RICHARD HARE President, National Fuel Gas Supply Corporation Your Company is, indeed, the “Gateway to the East” ... We stand directly between the gas supplies heading from Western Canada to the East Coast markets ... 10 Pipeline and Storage Currently the third largest segment in terms gas-powered combined-cycle electric genera- of net plant, this segment continued to be a tion plants and gas peaking units and the strong contributor to Company earnings, anticipated construction of new power plants, second only to the Utility. Net income of the vast majority of which will be gas-fired.* $39.8 million, or $1.03 per share, provided Some of the reasons for gas-fired electric gen- nearly 35% of 1999 Company earnings. eration include reduced environmental air In anticipation of the growing demand quality issues from coal-fired generation and for natural gas in the East Coast markets, a efficiencies from technological advances in portion of this year’s capital budget was spent combined-cycle turbines and other types of expanding the throughput capacity of our gas-fired units.* This anticipated movement Ellisburg, Pennsylvania compressor station towards gas-fired generation presents tremen- from 369 MMcf per day to over 431 MMcf dous growth opportunities for gas pipeline per day. This additional capacity is designed companies.* to increase both pipeline throughput and Much of this new power plant construc- storage customer access to Leidy Hub, a key tion is expected to be directed to, and con- link to the East Coast. We also anticipate structed near, the East Coast markets.* The expanding capacity incrementally in the question then becomes, where will these Niagara Spur as demand increases.* power generators get the gas for these new Discussion at this Fall’s annual meeting plants? We expect that some of it will come of the Interstate Natural Gas Association of from the Gulf Coast, but that supply is likely America centered on the increasing use of Plans are in place to construct and operate the Independence Pipeline, a 370-mile interstate pipeline, of which we are 1/3 owner. This pipeline would trans- port about 900,000 Dth per day CHICAGO of natural gas from Defiance, Ohio to Leidy, Pennsylvania. CANADA BUFFALO ERIE LEIDY HUB Right, A $5.7 million investment was made in this 3,200 horse- power compressor at the Ellisburg, Pennsylvania Station, near the Leidy Hub. Put into service in March 1999, this new equipment increased capacity for both pipeline throughput and customer access to storage. Below, Dramatic gas flare-ups at Summit Storage Field near Erie, Pennsylvania could be seen from quite a distance. This operation removes deposits that have accu- mulated in the wells and improves deliverability of natural gas out of the storage field. National Fuel Pipelines Independence Pipeline Project Supply Link Market Link to mainly feed the West Coast, lower Rockies, and the Southeast.* Much of the gas is there- fore expected to come from the hubs near Chicago which are fed by Canadian producers via the Northern Border Pipeline Expansion, completed in 1998, and the Alliance Pipeline, which is currently under construction.* With this influx of Canadian gas, Chicago should have pent up capacity, while markets on the East Coast are expected to have pent up demand.* Consequently, capacity needs to be made available to move gas from Chicago eastward.* Another pipeline project, Vector, has received approval from the Federal Energy Regulatory Commission (FERC) to build a pipeline from Chicago to Dawn, Ontario. Designed to transport 1 Bcf per day of gas, we understand the Vector Pipeline has approximately half of its capacity subscribed to Eastern Canadian markets.* We expect the remaining capacity from Vector should most logically come across the Niagara River and through our system.* Of course, we are convinced that the best route for the Canadian gas is still through the Independence Pipeline. We are pursuing this $680 million project with our partners, affili- ates of Transcontinental Gas Pipe Line Corporation (one of the Williams Companies) and ANR Pipeline Company (a subsidiary of The Coastal Corporation).* This pipeline, when constructed, should be the key link in a chain of pipelines from the Canadian Rockies to the East Coast.* In November 1999 the project received the FERC final Environ- mental Impact Statement which is a very pos- itive step toward project certification. We are awaiting final certification of the project. We believe that by supplying over 900,000 Dth per day of gas to the East Coast markets, this pipeline will be instrumental in capitalizing on the anticipated movement by the power generation industry toward gas-fired genera- tion.* Your Company is, indeed, the “Gateway to the East” more so than it has ever been. We stand directly between the gas supplies heading from Western Canada to the East Coast markets, and we believe our pipeline and storage facilities are strategically located to take advantage of this growth opportunity.* 11 Plastic pipe is now used more frequently by the Utility for mainline replacement projects. In addition to being lighter and more flexible than steel pipe, it is resistant to corrosion and lessens the time and costs associated with pipe fitting and welding. DAVID F. SMITH President, National Fuel Gas Distribution Corporation Utility This segment’s earnings of $56.9 million, or During 1999, the local and national $1.47 per share, contributed the largest media made much of customer choice for portion, approximately 49%, of the utility customers. Electric choice initiatives in Company’s net income in 1999. This is a New York and Pennsylvania jumped into the remarkable achievement since our two year spotlight as regulatory agencies launched rate settlement in New York required an public education programs and electric mar- annual rate reduction of $7.2 million, and keters began advertising campaigns for retail required us to set aside $7.2 million of 1999 customers. The publicity suggests that there revenues to fund future restructuring is a great deal of customer choice activity expenses incurred as New York State sepa- going on in the business, with customers rates the sale of gas from transportation. switching suppliers and telemarketers pitch- Our continuing emphasis on cost con- ing utility service and nontraditional products tainment has been instrumental in helping us to an ever-growing pool of eligible utility cus- to achieve better than expected results thanks tomers. In fact, however, the reality is some- to the efforts of our employees. By embracing what less exciting. While we have seen an the message of change, they helped us to increase in customer choice activity – cur- further reduce total operating and mainte- rently over 70,000 of our more than 733,000 nance expenses below last year’s figures. This customers have switched to transportation accomplishment is all the more noteworthy in service – we continue to manage the transi- light of the increased expense caused by our tion to competition as an evolutionary, con- early retirement initiatives. While we have seen an increase in customer choice activity... we remain focused on building restructured services that preserve relia- bility and provide a framework for fair competition. 12 Right, The Utility works with local businesses to support eco- nomic development. Over the summer, gas service lines were relocated to facilitate expansion of the Buffalo Bills’ Ralph Wilson Fieldhouse in Orchard Park, New York. Pictured here: Orchard Park Service Center personnel Patrick McNerney and Kevin McCarthy. sidered process. Choice as an end unto itself is a dubious proposition, and we remain focused on building restructured services that preserve reliability and provide a framework for fair competition. These efforts have yielded a successful choice program that we expect will continue to produce bene- fits for the Utility, the Company and our customers as the industry’s restructuring proceeds.* In an environment of rapid change, we have maintained the Utility’s steadfast dedica- tion to superior customer service. For Services Department in order to better and instance, new programs were established in more efficiently serve the needs of our trans- New York and Pennsylvania to provide gas portation customers. We continued to appliance repairs or replacement for some of enhance our field procedures to allow more our neediest customers. We continued to customers to initiate or transfer service work with local social service agencies to without having to provide access to Company bring the benefits of competition to thou- personnel. Finally, our traditional service per- sands of public assistance customers who formance measures continued to improve or might otherwise be overlooked as a potential remain at historically high levels. market. We organized a Transportation We have also scrutinized the Utility’s A new vacuum truck is now used throughout the Utility service territory. This equipment, often used in place of a backhoe, mini- mizes the size of construction sites thus reducing both restora- tion costs and related customer complaints. Pictured here: Jurel Hunt and Michael Siler of the Construction Department. practices and procedures in order to identify opportunities for technology improvement and efficiency gains. Currently, we are installing a new PeopleSoft® system that will greatly enhance our ability to retrieve and efficiently process financial and accounting information. Additionally, we are modifying our Customer Information System to allow UTILITY OPERATION AND MAINTENANCE EXPENSE Millions of Dollars 201 194 187 184 182 9 5 9 6 9 7 9 8 9 9 13 Training and preliminary imple- mentation has begun for the PeopleSoft® Financials system. This new accounting and finan- cial system is intended to improve timeliness of reporting as well as to simplify access to information. Pictured here: Marjorie Minotti instructs employee implementation team members, from left, Mark Kraemer, Robert Schneggen- burger, Susan Bender, Joseph Short and Brian Hirsch. Utility employees closely monitor ground water levels following a two year long environmental clean-up recently completed at the Erie, Pennsylvania Service Center. Pictured here: Tanya Alexander and Joseph Hartleb. line problems easier and less costly to isolate and repair. Finally, we are exploring a number of value added services and products designed to increase revenues from our existing cus- tomer base. In the Utility’s service territories, National Fuel is a name that customers have long trusted for reliable gas service and expert energy advice. Particularly during these times of rapid change, opportunities for for more flexibility in customer and marketer the Utility to offer nontraditional products billing functions. In the field, technological and services are at their greatest. As a result, advances have allowed our personnel to we are looking at energy end-use technolo- respond more effectively and efficiently to gies, including microturbines and distributed many situations, from environmental site generation projects, retail billing services, monitoring to pipeline system repairs and pipeline insurance and appliance leasing, maintenance. For example, by using a among other things. Indications are promis- “vacuum” truck for line repairs, we signifi- ing that customers would be strongly inter- cantly reduced the cost of gas line mainte- ested in these and other products and ser- nance and site restoration costs. We are also vices offered by the Utility.* using a “gas cam” which allows our crews to In these changing times, we believe it is “see” through a tiny camera inserted into a particularly important that we remain focused pipe, thereby making corrosion and other on the fundamentals. Thus, we will continue to emphasize our strengths: cost containment, superior customer service, and a managed transition to competition. At the same time, however, change presents new opportunities. We look forward to exploring those opportu- nities during the next year and as the busi- ness environment continues to evolve. NEW SERVICE COMMITMENTS NON–EMERGENCY APPOINTMENTS Percent of Orders Completed Percent of Within 10 Days Appointments Kept 99.8 99.8 99.1 99.1 98.8 98.5 97.8 97.0 96.8 97.9 14 9 5 9 6 9 7 9 8 9 9 9 5 9 6 9 7 9 8 9 9 Through deregulation, gas mar- keters such as National Fuel Resources can offer homeowners the opportunity to receive savings on their natural gas bills. ROBERT J. KREPPEL President, National Fuel Resources, Inc. Regulatory changes in New York have been most favor- able, and, as a result, our most dynamic growth has taken place there. Energy Marketing In what may be a unique record among gas prices.* Providing energy solutions for cus- company marketing affiliates, each year since tomers cannot be limited to natural gas and its inception in 1991 National Fuel related value added services. We are also pur- Resources, Inc. (NFR) has contributed posi- suing opportunities related to gas-fired gener- tively to Company earnings. In 1999, net ation which could position us for future retail income of $2.1 million, or $.05 per share, electric opportunities.* While retail electric provided a return on its equity of 16.8%. As prospects are modest at the moment, we are you can see from the charts provided, over confident that a fully competitive market will 75% of our customer growth is attributed to unfold over time and we will be well posi- residential gas customers, but the dramatic tioned for this opportunity.* increase in volumes was accomplished across- the-board with growth in all customer seg- ments. NFR has a multi-state presence and continues to expand its markets in New Jersey and Pennsylvania. However, regulatory changes in New York have been most favor- able, and, as a result, our most dynamic growth has taken place there. NFR has strategically acquired upstream pipeline capacity and storage to assure reli- able service to our customers at competitive NFR NUMBER OF CUSTOMERS NATURAL GAS MARKETING VOLUMES Bcf 17,480 34.5 26.5 20.2 21.0 18.8 5,476 1,307 246 672 9 5 9 6 9 7 9 8 9 9 9 5 9 6 9 7 9 8 9 9 Electric Residential Gas Commercial / Industrial Gas 15 At our electric generation and district heating plant in Komo´rany, Czech Republic, steam produced in nine high pressure boilers is used to fuel these eight turbine generators before being delivered to the primary pipeline as an energy source for industrial and municipal heating customers. Below, PSZT employees dispatch electricity to the local distribu- tion grid from this control center 24 hours a day and 365 days a year. BRUCE H. HALE Vice President, Horizon Energy Development, Inc. Future growth could come from a joint venture or similar alliance, preferably with a U.S.-based electric company.* 16 International Net income of $2.3 million, or $.06 per company.* We believe their knowledge of share, is a gratifying result from this rela- electricity and our natural gas expertise will tively new segment. These earnings were $1.0 provide enhanced development million or 78% higher than 1998’s earnings opportunities.* of $1.3 million. This year also marked the We are comfortable with our base in first full 12 months of sales and revenues Prague which allows us to look at numerous from our investment in První severozápadní prospects within Eastern Europe. As you may teplárenská, a.s. (PSZT). know, projects here happen later rather than Capital expenditures of $27.6 million sooner; thus, patience and a long-term view were used primarily for the construction of are key considerations as we continue to eval- new boilers at our PSZT heating plant to uate potential energy projects.* comply with certain clean air standards man- dated by the Czech Republic. Our net plant in the Czech Republic now stands at $203.5 million with total assets of $255.0 million. The merger of Severoc˘eské teplárny, a.s. (SCT) and PSZT is expected to occur in 2000, and should provide efficiency improvements and cost reductions.* Future growth could come from a joint venture or similar alliance, preferably with a U.S.-based electric 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, 1999 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- 6980 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 $1,907,786,000 as of November 30, 1999. Common Stock, $1 Par Value, outstanding as of November 30, 1999: 38,966,378 shares. DOCUMENTS INCORPORATED BY REFERENCE Portions of the registrant’s Annual Report to Shareholders for 1999 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 17, 2000 are incorporated by reference into Part III of this report. N a t i o n a l F u e l G a s C o m p a n y 17 Form10-K For the Fiscal Year Ended September 30, 1999 Part I I T E M 1 Business The Company and its Subsidiaries 19 Rates and Regulation 21 The Utility Segment 22 The Pipeline and Storage Segment 22 The Exploration and Production Segment 22 The International Segment 22 The Energy Marketing Segment 23 The Timber Segment 23 Sources and Availability of Raw Materials 23 Competition 24 Seasonality 25 Capital Expenditures 26 Environmental Matters 26 Miscellaneous 26 Executive Officers of the Company 26 Properties General Information on Facilities 27 Exploration and Production Activities 28 Legal Proceedings 29 Submission of Matters to a Vote of Security Holders 29 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 Quantitative and Qualitative Disclosures About Market Risk 57 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 89 Certain Relationships and Related Transactions 89 Exhibits, Financial Statement Schedules, and Reports on Form 8-K 90 Part II I T E M 2 I T E M 3 I T E M 4 I T E M 5 I T E M 6 I T E M 7 I T E M 7A I T E M 8 I T E M 9 I T E M 1 0 I T E M 1 1 I T E M 1 2 I T E M 1 3 s t n e t n o C N a t i o n a l F u e l G a s C o m p a n y 18 Part III Part IV I T E M 1 4 S I G N AT U R E S 93 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 The Company and its 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 on December 8, 1902. The Company is engaged in the busi- ness of owning and holding securities issued by its subsidiary companies. Except as otherwise indi- cated below, the Company owns all of the outstanding securities of its subsidiaries. Reference to “the Company” in this report means the Registrant or the Registrant and its subsidiaries collectively, as appropriate in the context of the disclosure. The Company is a diversified energy company consisting of the six reportable business segments. This report includes two newly-reported segments — Energy Marketing and Timber — and no longer includes the previously reported “Other Nonregulated” segment. As a result of these refinements in the Company’s reportable segments, where appropriate in this report the information for 1998 and 1997 has been restated from the prior year’s presentation to conform to the 1999 presentation. 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 and provides natural gas transportation services through a local distribution system located in western New York and northwestern Pennsylvania (principal metropolitan areas: Buffalo, Niagara Falls and Jamestown, New York; 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 transporta- tion 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) 29 underground natural gas storage fields owned and operated by Supply Corporation and four other underground natural gas storage fields operated jointly with various major interstate gas pipeline companies. SIP holds a one-third general partnership interest in Independence Pipeline Company (Independence), a Delaware general partnership. Independence, after receipt of reg- ulatory approvals and upon securing sufficient customer interest, plans to construct and operate the Independence Pipeline, a 370-mile interstate pipeline system which would transport about 900,000 dekatherms per day (Dth/day) of natural gas from Defiance, Ohio to Leidy, Pennsylvania.* N a t i o n a l F u e l G a s C o m p a n y 19 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, and in California, Wyoming and in the Appalachian region of the United States. 4. The International segment operations are carried out by Horizon Energy Development, Inc. (Horizon), a New York corporation. Horizon engages in foreign energy projects through the invest- ments of its indirect subsidiaries as the sole or substantial owner of various business entities. Horizon is the sole shareholder of Horizon Energy Holdings, Inc., a New York corporation which in turn owns 100% of Horizon Energy Development B.V. (Horizon B.V.). Horizon B.V. is a Dutch company whose principal assets consist of a majority ownership in (i) Severo˘ceské teplárny, a.s. (SCT), a company with district heating and power generation operations located in the northern part of the Czech Republic; (ii) První severozápadní teplárenská, a.s. (PSZT), a wholesale power and district heating company that is located in the Czech Republic in close proximity to SCT; and (iii) Teplárna Krom˘e˘rí˘z, 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 residen- tial end-users throughout the northeast United States. 6. The Timber segment operations are carried out by Highland Land & Minerals, Inc. (Highland), a Pennsylvania corporation, and by a division of Seneca known as its Northeast Division. Highland owns four sawmill operations in northwestern Pennsylvania and processes timber consisting primarily of high quality hardwoods. The Northeast Division of Seneca markets timber from its New York and Pennsylvania land holdings. 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 discussion of the Company’s business segments as contained in the business segment discussion on pages 7 to 16 of this combined Annual Report to Shareholders/Form 10-K is incorporated herein by reference. 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) (formerly known as Niagara Energy Trading Inc.), a New York corpo- ration 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 partnership. DirectLink was formed to engage in natural gas marketing and related businesses, in part by subscribing for firm transportation capacity on the Independence Pipeline; • Leidy Hub, Inc. (Leidy), a New York corporation formed to provide various natural gas hub services to customers in the eastern United States through a 50% ownership of Ellisburg-Leidy Northeast Hub Company (a Pennsylvania general partnership); • Data-Track Account Services, Inc. (Data-Track), a New York corporation which provides collection services principally for the Company’s subsidiaries; and N a t i o n a l F u e l G a s C o m p a n y 20 Rates and Regulation • NFR Power, Inc. (NFR Power), a New York corporation capitalized by the Company in 1999 which, while not actively generating electricity at this time, is designated as an “exempt wholesale generator” under the Holding Company Act. No single customer, or group of customers under common control, accounted for more than 10% of the Company’s consolidated revenues in 1999. Any reference to a year in this report is to the Company’s fiscal year ended September 30 of that year unless otherwise noted. 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 limita- tions on diversification. The SEC and some members of Congress have advocated, on either a stand- alone basis or in conjunction with legislation which would deregulate the electric industry, the repeal of the Holding Company Act. The proposed legislation currently under consideration 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. Such legislation could actually increase regulation of the Company, especially at the state level. Previous SEC rule changes, however, 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 current or future legislative and/or regulatory initia- tives 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 rates, services and other matters will be regulated by the FERC. For additional discussion 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 regula- tory 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 regulation 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 regu- lations on various subjects as other companies doing similar business in the same locations. N a t i o n a l F u e l G a s C o m p a n y 21 The Utility Segment The Utility segment contributed approximately 49.4% of the Company’s net income available for common stock in 1999. Additional discussion of the Utility segment appears in the business segment discussion con- tained in this combined Annual Report to Shareholders/Form 10-K, below in this Item 1 under the headings “Sources and Availability of Raw Materials” and “Competition,” in Item 7, MD&A and in Item 8 at Notes B - Regulatory Matters, H - Commitments and Contingencies and I - Business Segment Information. The Pipeline and Storage Segment The Pipeline and Storage segment contributed approximately 34.6% of the Company’s net income available for common stock in 1999. Supply Corporation currently has service agreements for substantially all of its firm transporta- tion capacity, which totals approximately 1,943 million cubic feet (MMcf) per day. The Utility segment has contracted for approximately 1,126 MMcf per day or 58% of that capacity until 2003 and continu- ing year-to-year thereafter. An additional 25% 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 62.8 billion cubic feet (Bcf) of firm storage capacity. The Utility segment has contracted for 26.0 Bcf or 41% of that capacity, in service agreements with remaining initial terms of approximately 4 to 7 years and continuing year-to- year thereafter: 23.3 Bcf - 4 years; 2.0 Bcf - 7 years and 0.7 Bcf - 5 years. Nonaffiliated customers have contracted for the remaining 36.8 Bcf or 59% of firm storage capacity; 12.1 Bcf or 19% 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.* Independence has filed with the FERC signed precedent agreements providing for firm trans- portation service totaling about 629,000 Dth/day for ten years, out of total proposed transportation capacity of about 900,000 Dth/day. The customer for 500,000 Dth/day of that total is DirectLink, which is owned by the sponsors of the Independence Pipeline, including NIM. Additional discussion of the Pipeline and Storage segment appears in the business segment dis- cussion contained in this combined Annual Report to Shareholders/Form 10-K, below under the head- ings “Sources and Availability of Raw Materials” and “Competition,” Item 7, MD&A and Item 8 at Notes B - Regulatory Matters, H - Commitments and Contingencies and I - Business Segment Information. The Exploration and Production Segment The Exploration and Production segment contributed approximately 6.2% of the Company’s net income available for common stock in 1999. Additional discussion of the Exploration and Production segment appears in the business segment discussion contained in this combined Annual Report to Shareholders/Form 10-K, below under the headings “Sources and Availability of Raw Materials” and “Competition,” Item 7, MD&A and Item 8 at Notes A - Summary of Significant Accounting Policies, F - Financial Instruments, I - Business Segment Information, J - Stock Acquisitions and M - Supplementary Information for Oil and Gas Producing Activities. The International Segment The International segment contributed approximately 2.0% of the Company’s net income available for common stock in 1999. N a t i o n a l F u e l G a s C o m p a n y 22 Additional discussion of the International segment appears in the business segment discussion contained in this combined Annual Report to Shareholders/Form 10-K, below under the headings “Sources and Availability of Raw Materials” and “Competition,” Item 7, MD&A and Item 8 at Notes F - Financial Instruments, I - Business Segment Information and J - Stock Acquisitions. The Energy Marketing Segment The Energy Marketing segment contributed approximately 1.8% of the Company’s net income avail- able for common stock in 1999. Additional discussion of the Energy Marketing segment appears in the business segment discus- sion contained in this combined Annual Report to Shareholders/Form 10-K, below under the head- ings “Sources and Availability of Raw Materials” and “Competition,” Item 7, MD&A and Item 8 at Notes F - Financial Instruments and I - Business Segment Information. The Timber Segment The Timber segment contributed approximately 4.1% of the Company’s net income available for common stock in 1999. Additional discussion of the Timber segment appears in the business segment discussion con- tained in this combined Annual Report to Shareholders/Form 10-K, below under the headings “Sources and Availability of Raw Materials” and “Competition,” Item 7, MD&A and Item 8 at Note I - Business Segment Information. Sources and Availability of Raw Materials Natural gas is the principal raw material for the Utility segment. In 1999, the Utility segment pur- chased 112.4 Bcf of gas. Gas purchases from various producers and marketers in the southwestern United States under long-term (two years or longer) contracts accounted for 66% of these purchases. Purchases of gas in Canada and the United States on the spot market (contracts of less than a year) accounted for 29% of the Utility segment’s 1999 gas purchases. Gas purchases from Southern Company Energy Marketing L.P. and Dynegy Marketing and Trade represented 17% and 13%, respec- tively, of total 1999 gas purchases by the Utility segment. No other producer or marketer provided the Utility segment with 10% or more of its gas requirements in 1999. Supply Corporation transports and stores gas owned by its customers, whose gas originates in the southwestern 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 midwestern United States. The Exploration and Production segment seeks to discover and produce raw materials (natural gas, oil and hydrocarbon liquids) as described in the business segment discussion contained in this combined Annual Report to Shareholders/Form 10-K, 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, fuel oil, limestone and water combined account for the remaining 55% of such materials. Coal is purchased and delivered directly from the Mostecka Uhelna Spolec˘nost, a.s. mine for Horizon’s largest coal-fired plant under a contract where price and quantity are the subject of negotiation each year. 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 Republic government and purchased by the International segment from two of the eight regional gas distribution companies. Fuel oil used to fire certain of the boilers is purchased from both domestic Czech Republic and foreign refineries. N a t i o n a l F u e l G a s C o m p a n y 23 Competition The Energy Marketing segment depends on an adequate supply of natural gas and electricity. In 1999, this segment purchased approximately 34.5 Bcf of natural gas and approximately 73,000 megawatt hours of electricity. 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. 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 by removing some of the regulatory impediments to adding customers and responding to market forces.* In addi- tion, the environmental advantages of natural gas compared with other fuels should increase the role of natural gas as an energy source.* Moreover, natural gas is abundantly available in North America, which makes 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. 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. State restructur- ing initiatives are under way, with regulators in both New York and Pennsylvania adopting retail com- petition for natural gas supply purchases. However, the Utility segment’s traditional distribution func- tion remains largely unchanged. For further discussion of state restructuring initiatives refer to Item 7, MD&A under the heading “Rate Matters.” Competition for large-volume customers continues with local producers or pipeline companies attempting to sell or transport gas directly to end-users located within the Utility segment’s service ter- ritories (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 and/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 compa- nies 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-consuming regions of the eastern United States and gas-producing regions of Canada and the southwestern, southern and midwestern 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 Northeast and Mid-Atlantic United States markets. In combination with expansion projects of Transcontinental Gas Pipe Line N a t i o n a l F u e l G a s C o m p a n y 24 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 proposed pipelines will go forward and that the first project built will have an advantage over other proposed projects.* Independence is attempting to be the first of the proposed projects approved by the FERC and the first built.* 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 compa- nies of various sizes for leases and drilling rights for exploration and development prospects. To compete in this environment, Seneca originates and acts as operator on most prospects, mini- mizes risk of exploratory efforts through partnership-type arrangements, applies the latest technology for both exploratory studies and drilling operations and focuses on market niches that suit its size, operating expertise and financial criteria. Competition: The International Segment Horizon competes with other entities seeking to develop foreign and domestic energy projects. Horizon, through SCT and PSZT, faces competition in the sales of thermal energy to large industrial customers. Currently, electric energy sales are made to the regional electric distribution companies. The Czech Ministry of Finance has announced plans to privatize these distribution companies. While it is expected that these plans will increase competition at the retail level of the electric energy market, it is unclear at this point what impact this privatization will have on the wholesale electric energy market.* Both SCT and PSZT sell 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 primarily from both local and regional marketers. Competition: The Timber Segment Highland competes with other sawmill operations and Seneca competes with other suppliers of timber. This competition may be local, regional, national or international in scope. These competitors, however, are primarily limited to those entities which either process or supply high quality hardwoods species, such as cherry, oak and maple as veneer, or saw logs or export logs ultimately used in the pro- duction 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. N a t i o n a l F u e l G a s C o m p a n y 25 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 con- straints. The timber harvesting and processing season occurs when timber growth is dormant and runs from approximately 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. Capital Expenditures A discussion of capital expenditures by business segment is included in Item 7, MD&A under the heading “Investing Cash Flow” and subheading “Expenditures for Long-Lived Assets.” 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. Miscellaneous The Company had a total of 3,807 full-time employees at September 30, 1999, 2,401 employees in all of its U.S. operations and 1,406 employees in its International segment. This represents a decrease of 3.47% from the 3,944 total employed at September 30, 1998. Agreements covering employees in collective bargaining units in New York were renegotiated in November 1997, effective December 1997, and are scheduled to expire in February 2001. Agreements covering most employees in collective bargaining units in Pennsylvania have been renegotiated, come in effective 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 of Name and Age Current Company Positions and Other Material Business Experience During Past 5 Years (2) the Company (1) Bernard J. Kennedy (68) Philip C. Ackerman (55) Richard Hare (61) David F. Smith (46) Chairman of the Board of Directors since March 1989, Chief Executive Officer since August 1988 and Director since March 1978. Mr. Kennedy previously served as President from January 1987 to July 1999. President since July 1999 and Director since March 1994. Mr. Ackerman has served as Executive Vice President of Supply Corporation since October 1994 and President of Horizon since September 1995. He previously served as Senior Vice President from June 1989 to July 1999 and as President of Distribution Corporation from October 1995 to July 1999. President of Supply Corporation since June 1989. Mr. Hare previously served as Senior Vice President of Penn-York Energy Corporation from June 1989 until its merger into Supply Corporation in July 1994. President of Distribution Corporation since July 1999. Mr. Smith previously served as Senior Vice President of Distribution Corporation from January 1993 to July 1999. N a t i o n a l F u e l G a s C o m p a n y 26 Name and Age Current Company Positions and Other Material Business Experience During Past 5 Years (2) James A. Beck (52) Joseph P. Pawlowski (58) Gerald T. Wehrlin (61) 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 as Executive Vice President of Seneca from May 1995 to September 1996. Treasurer since December 1980. Mr. Pawlowski has served as Senior Vice President of Distribution Corporation since February 1992, 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. Mr. Wehrlin has served as Senior Vice President of Distribution Corporation since April 1991, Controller of Seneca since September 1981 and Vice President of Horizon since February 1997. He previously served as Secretary and Treasurer of Horizon from September 1995 to February 1997. Walter E. DeForest (58) Senior Vice President of Distribution Corporation since August 1993. Bruce H. Hale (50) 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. Dennis J. Seeley (56) Senior Vice President of Distribution Corporation since February 1997. Mr. Seeley previously served as Senior Vice President of Supply Corporation from January 1993 to February 1997. Robert J. Kreppel (42) President of NFR since March 1995. Mr. Kreppel previously served as Vice President of NFR from February 1992 to March 1995. (1) The Company has been advised that there are no family relationships among any of the officers listed, and that there is no arrange- ment 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) The information provided relates to positions within the Company and, where identified, the principal subsidiaries of the Company. Many of the executive officers have in the past served or currently serve as officers for other subsidiaries of the Company. I T E M 2 Properties General Information on Facilities The investment of the Company in net property, plant and equipment was $2.4 billion at September 30, 1999. Approximately 59% of this investment is in the Utility and Pipeline and Storage segments, which are primarily located in western New York and western Pennsylvania. The remaining invest- ment in property, plant and equipment is mainly in the Exploration and Production segment (29%), which is primarily located in the Gulf Coast, southwestern, western and Appalachian regions of the United States, the International segment (9%) which is located in the Czech Republic, and the Timber segment (3%) 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 transportation customers, to augment the reserve base of oil and gas, and to purchase district heating and power generation facili- ties in the Czech Republic. Net property, plant and equipment has increased $808.3 million, or 52%, since 1994. The Utility segment has the largest net investment in property, plant and equipment, compared with the Company’s other business segments. The net investment in its gas distribution network (including 14,773 miles of distribution pipeline) and its services represent approximately 58% and 29%, respectively, of the Utility segment’s net investment of $919.6 million at September 30, 1999. N a t i o n a l F u e l G a s C o m p a n y 27 The Pipeline and Storage segment represents a net investment of $466.5 million in property, plant and equipment at September 30, 1999. Transmission pipeline, with a net cost of $145.3 million, represents 31% of this segment’s total net investment and includes 2,583 miles of pipeline required to move large volumes of gas throughout its service area. Storage facilities consist of 33 storage fields, 4 of which are jointly operated with certain pipeline suppliers, and 482 miles of pipeline. Net invest- ment in storage facilities includes $85.1 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 purposes, including that needed for no-notice transporta- tion service. The Pipeline and Storage segment has 29 compressor stations with 74,646 installed com- pressor horsepower. The Exploration and Production segment had a net investment in property, plant and equipment amounting to $674.8 million at September 30, 1999. The International segment had a net investment in property, plant and equipment amounting to $203.5 million at September 30, 1999. PSZT’s net investment in district heating and electric genera- tion facilities was $147.5 million; SCT’s net investment in district heating and electric generation facil- ities was $55.0 million; and TK’s net investment in district heating facilities was approximately $1.0 million. The Timber segment had a net investment in property, plant and equipment of $88.9 million at September 30, 1999. Located primarily in northwestern Pennsylvania, the net investment includes 4 sawmills and approximately 140,000 acres of timber. The Utility and Pipeline and Storage segments’ facilities provided the capacity to meet its 1999 peak day sendout, including transportation service, of 1,909 MMcf, which occurred on January 5, 1999. Withdrawals from storage of 687 MMcf provided approximately 36% of the requirements on that day. Company maps are included on pages 2 and 3 of this combined Annual Report to Shareholders/Form 10-K and are incorporated herein by reference. 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, 1999 were estimated by Seneca’s qualified geologists and engineers and were audited by independent petroleum engineers from Ralph E. Davis Associates, Inc. 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: PRODUCTION For the Year Ended September 30 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. 1 9 9 9 1 9 9 8 1 9 9 7 $2.20 $12.85 $2.45 $12.15 $2.60 $20.63 $0.46 $0.45 $0.35 PRODUCTIVE WELLS At September 30, 1999 Productive Wells – gross – net Gas 1,934 1,801 Oil 895 845 Exploration and Production Activities N a t i o n a l F u e l G a s C o m p a n y 28 DEVELOPED AND UNDEVELOPED ACREAGE At September 30 Developed Acreage Undeveloped Acreage – gross – net – gross – net 1 9 9 9 636,221 558,651 1,043,757 753,106 DRILLING ACTIVITY For the Year Ended September 30 Net Wells Completed PRESENT ACTIVITIES At September 30 Wells in Process of Drilling Productive Dry 1 9 9 9 1 9 9 8 1 9 9 7 1 9 9 9 1 9 9 8 1 9 9 7 – Exploratory – Development 12.95 95.26 10.72 14.11 4.21 1.84 5.64 4.75 4.97 2.00 3.49 1.60 – gross – net 1 9 9 9 13.00 10.01 South Lost Hills Waterflood Program In Seneca’s South Lost Hills Field (acquired in 1998 as part of the HarCor Energy, Inc. and Bakersfield Energy Resources, Inc. acquisitions) 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 27 injection wells and 88 production wells in the program. The total injection and production from this waterflood project are 7,000 barrels of water per day and 400 barrels of oil per day, respectively. I T E M 3 Legal Proceedings For a discussion of various environmental matters, refer to Item 7, MD&A of this report under the heading “Other Matters” and to Item 8 at Note H - Commitments and Contingencies. 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 1999. Part II I T E M 5 Market for the Registrant’s Common Stock and Related Shareholder Matters Information regarding the market for the Registrant’s common stock and related shareholder matters appears in Note D - Capitalization and Note L - Market for Common Stock and Related Shareholder Matters (unaudited) under Item 8 of this combined Annual Report to Shareholders/Form 10-K, and reference is made thereto. On July 1, 1999, the Company issued 700 unregistered shares of Company common stock to the seven non-employee directors of the Company, 100 shares to each such director. These shares were issued as partial consideration for the directors’ service as directors during the quarter ended September 30, 1999, pursuant to the Company’s Retainer Policy for Non-Employee Directors. These transactions were exempt from registration by Section 4(2) of the Securities Act of 1933, as amended, as transactions not involving any public offering. N a t i o n a l F u e l G a s C o m p a n y 29 I T E M 6 Selected Financial Data Year Ended September 30 1 9 9 9 1 9 9 8 1 9 9 7 1 9 9 6 1 9 9 5 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 Net Income Available for Common Stock 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) $1,263,274 $1,248,000 $ 1,265,812 $ 1,208,017 $ 975,496 405,925 55,788 323,888 91,146 129,690 – 64,829 441,746 37,837 319,769 92,817 118,880 128,996 24,024 528,610 1,489 286,537 100,549 111,650 — 68,674 477,357 — 309,206 99,456 98,231 — 66,321 1,071,266 1,164,069 1,097,509 1,050,571 192,008 12,343 204,351 87,698 (1,616) 115,037 – $ 115,037 $ $2.98 $2.95 $1.83 $1.82 $1.86 83,931 35,870 119,801 85,284 (2,213) 32,304 (9,116) 23,188 $0.61(1) $0.60(1) $1.77 $1.76 $1.80 168,303 3,196 171,499 56,811 — 157,446 3,869 161,315 56,644 — 114,688 — $ 114,688 104,671 — $ 104,671 $ $3.01 $2.98 $1.71 $1.70 $1.74 $2.78 $2.77 $1.65 $1.64 $1.68 351,094 — 292,505 91,837 71,782 — 43,879 851,097 124,399 5,378 129,777 53,883 — 75,894 — 75,894 $2.03 $2.03 $1.60 $1.59 $1.62 22,336 23,743 20,267 21,640 21,429 $ 919,642 466,524 674,813 203,452 489 88,904 63 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 $ 822,764 463,647 339,950 70 54 22,146 420 131 $2,353,894 $2,248,137 $ 1,819,366 $1,709,606 $1,649,182 $2,842,586 $2,684,459 $ 2,267,331 $2,149,772 $2,036,823 CAPITALIZATION (Thousands) Common Stock Equity Long-Term Debt, Net of Current Portion Total Capitalization $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 $800,588 474,000 $1,274,588 (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 dis- cussion of these items in Notes to Financial Statements, Note A - Summary of Significant Accounting Policies. N a t i o n a l F u e l G a s C o m p a n y 30 I T E M 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations The Revenue Dollar – 1999 WHERE IT CAME FROM: 45.6¢ Residential Gas Sales 11.5¢ Commercial, Industrial and Off-System Gas Sales 10.0¢ Oil and Gas Production Revenues WHERE IT WENT TO: 8.5¢ Gas Transportation Revenues 7.8¢ Energy Marketing Revenues 5.6¢ District Heating Revenues 2.8¢ Gas Storage Service Revenues 2.7¢ Electric Generation Revenues 2.4¢ Timber and Sawmill Revenues 3.1¢ Other Revenues 100.0¢ Total 31.9¢ Gas Purchased 15.1¢ Wages, Including Benefits 12.2¢ Taxes 10.3¢ Other Materials and Services Interest 10.2¢ Depreciation 6.8¢ 5.5¢ Dividends — Common Stock 4.4¢ Fuel Used in Heat and Electric Generation 3.5¢ Reinvested in the Business 0.1¢ Minority Interest in Foreign Subsidiaries 100.0¢ Total R E S U LT S O F O P E R AT I O N S 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 fiscal 1997, which was recorded in the first quarter of fiscal 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) is the result of higher earnings in the Utility, Timber, Energy Marketing and International seg- ments 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. Additional discussion of earnings in each of the business segments can be found in the business segment information that follows. 1998 Compared with 1997 The Company’s earnings were $23.2 million, or $0.61 per common share ($0.60 per common share on a diluted basis), in 1998. These earnings include the two non-cash special items discussed above. Without these two non-cash 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). This compares with earnings of $114.7 million, or $3.01 per common share ($2.98 per common share on a diluted basis), in 1997. N a t i o n a l F u e l G a s C o m p a n y 31 The earnings decrease in 1998 was attributable to lower earnings of the Company’s Utility, Exploration and Production and Energy Marketing segments, offset in part by higher earnings in the Pipeline and Storage segment and in the International and Timber segments (both of which incurred a loss in 1997). Additional discussion of earnings in each of the business segments can be found in the business segment information that follows. Discussion of Asset Impairment and Cumulative Effect of a Change in Depletion Method Seneca follows the full-cost method of accounting for its oil and gas operations. Under this method, all costs directly associated with property acquisitions, exploration and development are capitalized, up to certain specified limits. Due to significant declines in oil prices in 1998, Seneca’s capitalized costs under the full-cost method of accounting exceeded these limits at March 31, 1998. Seneca was required to recognize an impairment of its oil and gas producing 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. Effective October 1, 1997, Seneca 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 1999 and 1998 has been computed under the units of production method. EARNINGS (LOSS) BY SEGMENT Year Ended September 30 (Thousands) Utility Pipeline and Storage Exploration and Production (1) (2) International Energy Marketing Timber Total Reportable Segments All Other Corporate Total Consolidated (1) (2) 1 9 9 9 1 9 9 8 1 9 9 7 $56,875 39,765 7,127 2,276 2,054 4,769 112,866 (162) 2,333 $115,037 $51,788 39,852 (64,110) 1,279 787 1,904 31,500 143 661 $32,304 $57,220 36,760 20,359 (3,348) 1,567 (609) 111,949 171 2,568 $114,688 (1) Before Cumulative Effect of a Change in Accounting in 1998. (2) 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) 1 9 9 9 1 9 9 8 1 9 9 7 Retail Revenues: Residential Commercial Industrial Off-System Sales Transportation Other N a t i o n a l F u e l G a s C o m p a n y 32 $581,022 101,482 15,903 $612,647 123,807 18,068 $709,968 167,338 22,412 698,407 754,522 899,718 29,214 77,600 2,134 44,479 62,844 9,335 43,857 49,285 (1,494) $807,355 $871,180 $991,366 UTILITY THROUGHPUT — (MMcf) Year Ended September 30 Retail Sales: Residential Commercial Industrial Off-System Sales Transportation Intrasegment Throughput 1 9 9 9 1 9 9 8 1 9 9 7 71,177 13,885 4,144 89,206 12,469 64,284 165,959 (198) 165,761 71,704 16,405 4,298 92,407 16,192 60,386 168,985 (306) 168,679 85,676 22,640 5,134 113,450 14,051 57,875 185,376 (565) 184,811 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. The recovery of lower gas costs (gas costs are recovered dollar for dollar in revenues) 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 billion cubic feet (Bcf) and a lower average cost of purchased gas (see discussion of purchased gas below under the heading “Purchased Gas”). Despite weather that was colder than the prior year, retail volumes sold decreased, mainly due to the migration of residential and small commercial retail cus- tomers to transportation service. This is the result of customers turning to marketers for their gas sup- plies while using Distribution Corporation for gas transportation service. (Restructuring in the Utility segment’s service territory is further discussed in the “Rate Matters” section that follows). Transportation revenue increased and volumes are up 3.9 Bcf as a result of the migration noted above and because of colder weather. Off-system revenue is down due to lower volumes sold of 3.7 Bcf. Off- system sales are a function of demand in the northeast markets. Record storage levels at the beginning of the 1998-99 heating season and a warmer than normal winter in 1998-99 reduced demand for off- system sales. The margins resulting from off-system sales are minimal. The decrease in other operating revenue of $7.2 million is due primarily to a $7.2 million gas restructuring reserve reducing revenue in the current year, $6.0 million of revenue recorded in 1998 as a result of Internal Revenue Service (IRS) audits and $0.5 million of a revenue reduction in the current year due to a final IRS audit settlement. These items are offset in part by a $7.1 million lower refund provision recorded in 1999 as compared with the 1998 refund provision. The gas restructuring reserve is to be applied against incremental costs resulting from the New York Public Service Commission’s (NYPSC) gas restructuring efforts (the NYPSC’s gas restructuring efforts are further dis- cussed in the “Rate Matters” section that follows). 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 settlements of 1996 and 1998. All of these items are included in the “Other” category of the Utility Operating Revenue table above. N a t i o n a l F u e l G a s C o m p a n y 33 1998 Compared with 1997 Operating revenues for the Utility segment decreased $120.2 million in 1998 compared with 1997. This resulted from a reduction in retail sales revenue of $145.2 million offset in part by higher off- system sales revenue, transportation revenue and other revenue of $0.6 million, $13.6 million and $10.8 million, respectively. The decrease in retail gas revenue was caused by the recovery of lower gas costs offset in part by a general base rate increase in the New York jurisdiction effective October 1, 1997. The recovery of lower gas costs resulted from a decrease in retail gas sales of 21.0 Bcf and a decrease in the average cost of purchased gas (see discussion of purchased gas below under the heading “Purchased Gas”). While the decrease in gas sales also reflects, in part, the migration of residential and small commercial retail customers to transportation service, the major reason for the decrease stems from warmer weather which was on average 13.8% warmer in 1998 than in 1997 (see Degree Days table below). The increase in other operating revenue of $10.8 million is due primarily to $6.0 million of revenue recorded in 1998 as a result of IRS audits, as discussed above, and $7.9 million of refund pool revenue, as discussed below, offset in part by a $4.7 million higher refund provision recorded in 1998 as compared with 1997. The refund provision represents the 50% sharing with customers of earnings over a predetermined amount in accordance with the New York rate settlement of 1996. As part of the 1996 rate settlement with the NYPSC, Distribution Corporation was allowed to utilize certain refunds from upstream pipeline companies and certain credits (referred to as the “refund pool”) to offset certain specific expense items. In September 1998, Distribution Corporation recognized $7.9 million of the refund pool as other operating revenue and recorded an equal amount of Operation and Maintenance (O&M) expense in accordance with the settlement agreement. 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 nega- tive impact on earnings in 1998. In addition, adjustments made relating to the final settlement of these audits had a positive impact to earnings in the current year. Absent the IRS audit items, earn- ings of the Utility segment were up $0.6 million from the prior year. Lower O&M and interest expenses, a lower refund provision in the current year (as noted in the revenue discussion 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 posi- tive contributors to earnings this year. These items offset the costs associated with the current year’s early retirement offers (which totaled $5.6 million, pretax, for this segment), 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 a special $7.2 million (pretax) reserve to be applied against incremental costs resulting from the NYPSC gas restructuring efforts, as discussed above. 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 addition, in periods of colder than normal weather, the WNC benefits Distribution Corporation’s New York customers. In 1999, the WNC in New York preserved earnings of approximately $0.6 million (after tax) as weather, overall, was warmer than normal for the period of October 1998 Earnings N a t i o n a l F u e l G a s C o m p a n y 34 through May 1999. Since the Pennsylvania rate jurisdiction does not have a WNC, uncontrollable weather variations directly impact earnings. In the Pennsylvania service territory, weather was 4.0% colder than 1998 and 9.9% warmer than normal. The Pennsylvania jurisdiction’s colder weather in 1999 compared with 1998 increased earnings by approximately $0.5 million (after tax). 1998 Compared with 1997 Utility segment 1998 earnings were $51.8 million, down $5.4 million from 1997. This decrease was largely the result of the Utility segment incurring interest expense in 1998, net of related rate recov- ery, in connection with the settlement of the primary issues relating to the previously referred to set- tlement of the IRS audits. Absent this interest expense, the Utility segment’s earnings were down $1.6 million as compared to 1997. Warmer weather in 1998 compared with 1997 was the primary cause of the decrease. Partly offsetting the earnings decrease caused by warmer weather, the Utility segment experi- enced a decrease in O&M expense as a result of management’s continued emphasis on controlling costs. Also contributing to this decrease, 1997 O&M expense included $0.9 million of pretax expenses associated with an early retirement offer to certain Pennsylvania operating union employees in 1997. In 1998, the WNC in New York preserved earnings of approximately $7.9 million (after tax) as weather, overall, was warmer than normal for the period of October 1997 through May 1998. In the Pennsylvania service territory, weather was 15.7% warmer than 1997 and 13.4% warmer than normal. The Pennsylvania jurisdiction’s warmer weather in 1998 compared with 1997 lowered earnings by approximately $4.0 million (after tax). DEGREE DAYS Year Ended September 30 1999: 1998: 1997: Buffalo Erie Buffalo Erie Buffalo Erie Normal 6,848 6,223 6,689 6,223 6,690 6,223 Actual 6,179 5,607 5,914 5,389 6,793 6,395 Percent (Warmer) Colder Than Normal Prior Year (9.8%) (9.9%) (11.6%) (13.4%) 1.5% 2.8% 4.5% 4.0% (12.9%) (15.7%) (5.7%) (5.5%) Purchased Gas The cost of purchased gas is currently the Company’s single largest operating expense. Annual varia- tions 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 combination 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 require- ments 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 trans- portation and storage, was $3.82 per thousand cubic feet (Mcf) in 1999, a decrease of 7.5% from the average cost of $4.13 per Mcf in 1998. The average cost of purchased gas in 1998 was 3% lower than the $4.26 per Mcf in 1997. N a t i o n a l F u e l G a s C o m p a n y 35 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 1 9 9 9 1 9 9 8 1 9 9 7 $ 91,659 476 92,135 63,655 173 63,828 12,820 $168,783 $ 93,362 985 94,347 62,850 655 63,505 13,131 $170,983 $ 92,027 831 92,858 64,147 74 64,221 15,615 $172,694 1 9 9 9 1 9 9 8 1 9 9 7 300,242 8,061 308,303 298,738 14,310 313,048 291,164 9,138 300,302 1999 Compared with 1998 Operating revenues decreased $2.2 million in 1999 compared with 1998. The decrease resulted pri- marily from lower firm transportation revenue of $1.7 million, lower interruptible transportation and storage service revenue of $1.0 million, lower net revenues from unbundled pipeline sales and open access transportation of $0.8 million and an accrual for a gas imbalance payable of $1.0 million. These items were offset in part by higher firm storage service revenue of $0.8 million and higher cashout revenue of $1.3 million. Approximately $1.0 million of the decrease in the firm transportation revenue related to “pass through” type items (i.e., surcharges and refunds) that correspondingly reduced O&M expense, thus having no bottom line earnings impact. Interruptible transportation and storage service revenue decreased (and interruptible 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. The higher cashout revenue (a cash resolution of a gas imbalance whereby a customer pays Supply Corporation for gas it receives in excess of amounts delivered into Supply Corporation’s system by the customer’s shipper) is offset by an equal amount of purchased gas expense, thus there is no bottom line earnings impact. 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 straight fixed-variable (SFV) rate design. However, as mentioned above, lower interruptible transportation volumes did negatively impact revenue for 1999. 1998 Compared with 1997 Operating revenues decreased $1.7 million in 1998 compared with 1997. The decrease resulted pri- marily from lower net revenues from unbundled pipeline sales and open access transportation of $1.8 million, lower firm storage service revenues of $1.3 million and lower cashout revenue of $1.1 million. These decreases were partially offset by an increase in firm transportation revenue of $1.3 million (resulting from demand charges related to the incremental expansion of this segment’s Niagara import facilities) and higher interruptible transportation and storage service revenues of $0.7 million. Transportation volumes in this segment increased 12.8 Bcf. As noted above, generally, volume N a t i o n a l F u e l G a s C o m p a n y 36 Earnings fluctuations do not have a significant impact on revenues as a result of Supply Corporation’s SFV rate design. However, the increase in capacity stemming from the above noted incremental expansion con- tributed to higher demand charge revenue. Higher interruptible transportation volumes also increased revenues. 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 transporta- tion agreement by a customer in the amount of $2.5 million (pretax), were offset by lower O&M and interest expenses. Items causing lower O&M expense in 1999 when compared to 1998 include the establishment of reserves, in 1998, for preliminary survey and investigation costs associated with a proposed incremental 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 $3.7 million of pretax expense in 1998. In 1999, Supply Corporation reversed $0.8 million (pretax) of the gathering project reserve as it recovered that amount from its former project partner. Also in 1999, Supply recovered, through insur- ance, $0.7 million (pretax) related to the Zoar base gas loss. Several significant items also increased O&M expense in 1999 when compared to 1998, including early retirement offers in 1999 (which totaled $1.4 million, pretax, for this segment) 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 $1.0 million (pretax) by selling preliminary engineering, survey, environmental and archeological information from this storage project to the Independence Pipeline Company (the Independence Pipeline project is dis- cussed further under “Investing Cash Flow,” subheading “Pipeline and Storage”). 1998 Compared with 1997 In the Pipeline and Storage segment, earnings for 1998 of $39.8 million increased $3.1 million when compared with 1997. This was mainly due to Supply Corporation’s portion of interest income from the previously mentioned settlement of IRS audits. Additional income tax expense related to certain unsettled issues was also recorded. Absent these IRS audit items, earnings would have been down $0.3 million when compared with 1997. This decrease reflects the lower revenues, as discussed above, and an increase in O&M expense. These items were offset in part by lower interest expense and a buyout of a firm transportation agreement by a customer in the amount of $2.5 million (pretax). The higher O&M expenses resulted primarily from the above noted establishment of reserves associated with a proposed incremental expansion project and a natural gas gathering project and the base gas loss at Zoar Storage Field. Partially offsetting these increases in O&M expense was the reversal of a portion of a reserve set up in a prior period for a storage project and the fact that 1997 O&M expense included $1.0 million of pretax expenses associated with an early retirement offer. N a t i o n a l F u e l G a s C o m p a n y 37 Exploration and Production Revenues EXPLORATION AND PRODUCTION OPERATING REVENUES Year Ended September 30 (Thousands) 1 9 9 9 1 9 9 8 1 9 9 7 Gas (after Hedging) Oil (after Hedging) Gas Processing Plant Other $ 83,229 52,050 11,751 (36) $146,994 $ 82,910 34,069 4,937 2,356 $124,272 $ 84,024 34,147 — 1,089 $119,260 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 pro- duction from the properties acquired in 1998). Refer to the tables below for production and price information. Revenue from Seneca’s gas processing plant, acquired as part of the HarCor Energy, Inc. (HarCor) and Bakersfield Energy Resources (BER) acquisitions in May and June 1998, was up $6.8 million. These items were partly offset by a negative mark-to-market revenue adjustment related to written options of $1.3 million. Refer to further discussion of written options in the “Market Risk Sensitive Instruments” section that follows and in Note F - Financial Instruments in Item 8 of this report. 1998 Compared with 1997 Operating revenues increased $5.0 million in 1998 compared with 1997. The main reason for the increase was the $4.9 million in revenues related to the gas processing plant acquired in 1998, as noted above. While this gas processing plant contributed a large amount of revenue, this revenue was basically offset by an equal amount of expense. Gas production revenues, net of hedging activities, decreased $1.1 million as a result of decreased production, offset in part by higher gas prices (after hedging). Refer to the tables below for production and price information. The gas production declines were mainly due to the shut-in of production during the Gulf hurricane season and tropical storms, as well as the expected decline in production of West Cameron 552 and delays in drilling due to lack of rig availability in the first half of the year. Oil production revenues, net of hedging activities, were basically even with 1997 as increased production was offset by lower oil prices (after hedging). The increase in oil production was mainly the result of West Coast production from the properties acquired in the Whittier Trust Company, HarCor and BER acquisitions. PRODUCTION VOLUMES Year Ended September 30 Gas Production (million cubic feet) Gulf Coast West Coast Appalachia Oil Production (thousands of barrels) Gulf Coast West Coast Appalachia 1 9 9 9 1 9 9 8 1 9 9 7 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 32,377 1,135 5,074 38,586 1,404 490 8 1,902 N a t i o n a l F u e l G a s C o m p a n y 38 Earnings AVERAGE PRICES Year Ended September 30 Average Gas Price/Mcf Gulf Coast West Coast Appalachia Weighted Average Weighted Average After Hedging Average Oil Price/bbl Gulf Coast West Coast(1) Appalachia Weighted Average Weighted Average After Hedging 1 9 9 9 1 9 9 8 1 9 9 7 $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 $2.60 $1.79 $2.79 $2.60 $2.18 $21.37 $18.49 $21.28 $20.63 $ 17.95 (1) 1999 and 1998 includes low gravity oil which generally sells for a lower price. Seneca utilizes price swap agreements and options to manage a portion of the market risk associ- ated with fluctuations in the price of natural gas and crude oil. Refer to further discussion of these hedging activities below under “Market Risk Sensitive Instruments” and in Note F - Financial Instruments in Item 8 of this report. 1999 Compared with 1998 In the Exploration and Production segment, 1999 earnings of $7.1 million are down $7.9 million (exclusive of the two non-cash special items in 1998) when compared with 1998. This is largely because the settlement of the primary issues of IRS audits of years 1977-1994 had a positive impact on earnings in the prior year. Absent the IRS audit items, earnings of the Exploration and Production segment were down $1.4 million from the prior year. 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. 1998 Compared with 1997 Earnings in the Exploration and Production segment were $15.0 million in 1998 (exclusive of the two non-cash special items), down $5.4 million from 1997. This segment’s 1998 earnings include interest income related to the previously mentioned settlement of IRS audits. Without the positive contribu- tion from this interest income, earnings would be down $12.1 million when compared with 1997. This decrease was mainly because of low oil prices, decreased gas production (for reasons discussed in the revenue section above) and higher lease operating and interest costs related to Seneca’s acquisition activities in 1998. These circumstances more than offset the positive contribution to earnings that resulted from higher oil production and higher gas prices (after hedging). N a t i o n a l F u e l G a s C o m p a n y 39 International Revenues INTERNATIONAL OPERATING REVENUES Year Ended September 30 (Thousands) 1 9 9 9 1 9 9 8 1 9 9 7 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. $ 71,974 34,158 913 $107,045 $49,560 22,774 3,925 $76,259 $1,887 — 23 $1,910 1 9 9 9 1 9 9 8 1 9 9 7 10,047,042 1,138,980 7,116,776 763,848 262,615 — 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. Sales and revenues for 1998 include only eight months of activity as PSZT was acquired in February 1998. 1998 Compared with 1997 Operating revenues increased $74.3 million in 1998 compared with 1997. The increase primarily reflects 100% of the revenues of SCT and PSZT for 1998. Horizon acquired a 34% equity interest in SCT in April 1997, subsequently increasing that interest to 36.8% by September 30, 1997 (and thus accounted for its investment in SCT under the equity method in 1997). During 1998, Horizon increased its ownership in SCT to 82.7% as of September 30, 1998. In February 1998, Horizon acquired a 75.3% equity interest in PSZT and subsequently increased its ownership interest to 86.2% as of September 30, 1998. The consolidation method was used to account for the investments in SCT and PSZT during 1998. 1999 Compared with 1998 The International segment’s 1999 earnings were $2.3 million, or $1.0 million higher than 1998 earn- ings. The current year’s earnings reflect a full twelve months of results from PSZT, while the prior year 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 $5.1 million pretax net gain associated with U.S. dollar denominated debt, which did not recur in the current year. This debt was converted to a Czech koruna denominated loan in December 1998. 1998 Compared with 1997 The International segment’s earnings of $1.3 million in 1998 were up $4.6 million when compared to the loss recognized in 1997. This segment realized increases from Horizon’s share of earnings from its two main investments in district heating and power generation operations located in the Czech Republic. Because of the change in the nature of operations of the International segment over the past three years, earnings comparisons between 1999, 1998 and 1997 may not be meaningful. Future rev- enues from district heating operations are expected to fluctuate with changes in weather.* Earnings N a t i o n a l F u e l G a s C o m p a n y 40 Energy Marketing Revenues ENERGY MARKETING OPERATING REVENUES Year Ended September 30 (Thousands) Natural Gas (after Hedging) Electricity Other ENERGY MARKETING VOLUMES Year Ended September 30 Natural Gas — (MMcf) 1 9 9 9 1 9 9 8 1 9 9 7 $97,514 1,551 23 $99,088 $86,877 253 57 $87,187 $70,054 — 44 $70,098 1 9 9 9 1 9 9 8 1 9 9 7 34,454 26,453 21,024 1999 Compared with 1998 Operating revenues increased $11.9 million in 1999 compared with 1998. This increase reflects 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. 1998 Compared with 1997 Operating revenues increased $17.1 million in 1998 compared with 1997. This increase reflects higher marketing volumes as NFR customers increased from 1,307 at September 30, 1997 to 5,476 at September 30, 1998. NFR utilizes exchange-traded futures and exchange-traded options to manage a portion of the market risk associated with fluctuations in the price of natural gas. Refer to further discussion of these hedging activities below under “Market Risk Sensitive Instruments” and in Note F - Financial Instruments in Item 8 of this report. 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 have increased 30% to 34.5 Bcf in 1999 from 26.5 Bcf in 1998 and margins were up from the prior year. These positive contributions to earnings were partly offset by higher expenses for labor, office expense and advertising. 1998 Compared with 1997 The Energy Marketing segment’s earnings for 1998 of $0.8 million were $0.8 million below 1997 earnings. Although volumes of natural gas marketed were up 5.4 Bcf, lower earnings reflect lower margins and higher O&M expense in 1998. The increase in O&M expense mainly resulted from expan- sion of NFR’s customer base into new market areas. Earnings N a t i o n a l F u e l G a s C o m p a n y 41 Timber Revenues TIMBER OPERATING REVENUES Earnings Year Ended September 30 (Thousands) Operating Revenues 1 9 9 9 1 9 9 8 1 9 9 7 $31,117 $17,805 $11,536 1999 Compared with 1998 Operating revenues for the Timber segment increased $13.3 million. This increase was primarily the result of higher timber sales by Seneca of $3.6 million and increased log sales and kiln dry lumber sales of $4.9 million and $4.2 million, respectively, by Highland. Revenue growth reflects the increased investment by this segment in timber and sawmills. 1998 Compared with 1997 Operating revenues for the Timber segment increased $6.3 million as a result of higher timber sales by Seneca and increased lumber sales resulting from Highland’s purchase in 1998 of two new lumber mills. Highland also had a full year of production from the mill it purchased in January 1997. 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%. These higher revenues were partly offset by higher O&M, depletion and interest expenses. Earnings growth reflects the increased investment by this segment in timber and sawmills. 1998 Compared with 1997 Timber segment earnings of $1.9 million in 1998 were up $2.5 million when compared to the loss rec- ognized in 1997. Higher revenues from the operations of two new sawmills purchased in 1998 helped drive the earnings increase. Other Income and Interest Charges Although variances in Other Income items and Interest Charges are discussed in the earnings discus- sion by segment above, following is a recap on a consolidated basis: Other Income Other income decreased $23.5 million in 1999 and increased $32.7 million in 1998. The 1999 decrease is 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 denominated debt carried on the balance sheet of PSZT 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 is a $2.4 million gain recorded in 1999 resulting from the demutualization of an insurance company. As a policyholder, the Company received stock of the insur- ance company as part of its initial public offering. The 1998 increase in other income is primarily due to the above noted $18.5 million of interest income related to the settlement of IRS audits, the $5.1 million net gain associated with U.S. dollar denominated debt, the $2.5 million buyout of a firm transportation agreement by a Pipeline and Storage segment customer, as well as $1.3 million of interest income on temporary cash investments of SCT and PSZT. N a t i o n a l F u e l G a s C o m p a n y 42 Interest Charges Interest on long-term debt increased $12.2 million in 1999 and $11.0 million in 1998. 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 acquisi- tion activity in the Exploration and Production and International segments. Other interest charges decreased $9.8 million in 1999 and increased $17.5 million in 1998. The decrease in 1999 compared to 1998, as well as the increase in 1998 compared with 1997, resulted pri- marily from the $11.7 million of interest expense recorded in 1998 related to the settlement of IRS audits. In addition, in 1999 and 1998, interest on short-term debt increased mainly as a result of higher average amounts of debt outstanding. C A P I TA L R E S O U R C E S A N D L I Q U I D I T Y The primary sources and uses of cash during the last three years are summarized in the following con- densed 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 1 9 9 9 1 9 9 8 1 9 9 7 $271.9 (260.5) (5.8) (3.6) 6.7 67.2 (15.6) 10.7 (69.9) (0.2) (2.1) $253.0 (393.2) (112.0) (5.5) 7.6 229.4 94.9 7.9 (67.0) (0.3) 1.6 $294.7 (214.0) (21.1) — 1.4 (107.3) 98.2 7.1 (64.3) — — $ (1.2) $ 16.4 $ (5.3) 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). Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially 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 $271.9 million in 1999, an increase of $18.9 million compared with the $253.0 million provided by operating activities in 1998. The increase is attributed primarily to the Utility segment’s contribution offset partly by a decrease in cash provided by operations in the Exploration and Production segment. The increase in the Utility segment is mainly the result of lower O&M expenditures combined with lower cash disbursements for taxes and interest. While cash receipts from gas sales and transportation service were down, this decrease was N a t i o n a l F u e l G a s C o m p a n y 43 substantially offset by lower gas purchase expenditures. The decrease to cash provided by operations in the Exploration and Production segment is primarily because of an increase in interest payments stemming from higher debt related to the acquisitions made in 1998. Investing Cash Flow Expenditures for Long-Lived Assets Expenditures for long-lived assets include additions to property, plant and equipment (capital expendi- tures) and investments in corporations (stock acquisitions) or partnerships, net of any cash acquired. The Company’s expenditures for long-lived assets totaled $269.9 million in 1999. The table below presents these expenditures by business segment: Year Ended September 30, 1999 (Millions) Utility Pipeline and Storage Exploration and Production International Energy Marketing Timber All Other Capital Expenditures Investments in Corporations or Partnerships Total Expenditures For Long- Lived Assets $ 47.0 31.2 97.6 27.6 0.3 56.7 0.1 $260.5 $ — 3.6 — 5.8 — — — $9.4 $ 47.0 34.8 97.6 33.4 0.3 56.7 0.1 $269.9 Utility The majority of the Utility capital expenditures were made for replacement of mains and main exten- sions, 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. SIP made a $3.6 million investment in 1999 in Independence and had an aggregate investment balance of $10.4 million at September 30, 1999. Independence is a Delaware general partnership in which SIP owns a one-third general partnership interest. SIP’s cash investments were financed with short-term borrowings. Independence intends to build a 370 mile natural gas pipeline (Independence Pipeline) from Defiance, Ohio to Leidy, Pennsylvania at an estimated cost of $680 million.* If the Independence Pipeline is not constructed, SIP’s share of the development costs (including SIP’s investment in Independence Pipeline Company) is estimated not to exceed $13.0 million.* Exploration and Production Exploration and Production segment capital expenditures included approximately $57.4 million on the offshore program in the Gulf of Mexico, including offshore drilling expenditures, offshore construc- tion and lease acquisition costs. The remaining $40.2 million of capital expenditures included onshore drilling and construction costs for wells located in Louisiana, Texas and California as well as onshore geological and geophysical costs, including the purchase of certain 3-D seismic data. Of this amount, approximately $20.4 million was spent on development drilling, workover, recompletion and facility construction costs on the leases acquired last year in the Midway Sunset, Lost Hills area of California. International The majority of the International segment capital expenditures were made by PSZT for the construc- tion of new fluidized-bed boilers at its district heating and power generation plant to comply with stricter clean air standards. Short-term borrowings and cash from operations were used to finance these capital expenditures. N a t i o n a l F u e l G a s C o m p a n y 44 In fiscal 1999, Horizon, through a wholly-owned subsidiary, increased its ownership interest in SCT to 82.87% for a minimal cost. SCT in turn increased its ownership interest in Jablonecká teplárenská a realitní, a.s. (JTR), a district heating plant in the northern Bohemia region of the Czech Republic, from 34% to 65.78%. The cost of acquiring these additional shares was approximately $5.8 million ($5.7 million, net of cash acquired) and was financed with short-term borrowings and cash from operations. Energy Marketing The capital expenditures consisted primarily of the purchase of furniture, equipment and computer hardware and software for NFR’s gas marketing operations. Timber The majority of the Timber segment’s capital expenditures consisted of the purchase of 36,300 acres of land and timber from PennzEnergy Company for approximately $47 million. The acquisition was financed with short-term borrowings. The remaining $9.7 million of capital expenditures in this segment were for other land, timber and equipment purchases. Other Investing Activities Other cash provided by or used in investing activities primarily reflects cash received on the sale of various subsidiaries investments in property, plant and equipment, and cash used for investments in a mutual fund. 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 2 0 0 0 2 0 0 1 2 0 0 2 $ 50.5 38.9 112.2 8.6 0.8 $211.0 $ 49.5 20.5 139.7 8.6 0.8 $219.1 $ 48.5 20.5 139.9 8.6 0.8 $218.3 Estimated capital expenditures for the Utility segment in 2000 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 2000 will be concentrated in the reconditioning of storage wells and the replacement of storage and transmission lines. The esti- mated capital expenditures also include approximately $9.4 million for the purchase of an additional interest in both the Niagara Spur Loop Line (a 49.2 mile, 30-inch pipeline extending from Lewiston, New York to East Aurora, New York) and the Ellisburg Leidy Line (pipelines and facilities extending from Ellisburg, Pennsylvania to Leidy, Pennsylvania).* Estimated capital expenditures in 2000 for the Exploration and Production segment includes approximately $78.3 million for the offshore program in the Gulf of Mexico. Of this amount, approxi- mately $53.3 million is intended to be spent on exploratory and development drilling. The estimated expenditures also includes approximately $33.9 million for the onshore program. Of this amount, approximately $29.7 million is intended to be spent on exploratory and development drilling.* Estimated capital expenditures for the International segment will be concentrated in the areas of improvements and replacements within the district heating and power generation plants in the Czech Republic.* N a t i o n a l F u e l G a s C o m p a n y 45 The Company continuously evaluates capital expenditures and investments in corporations and partnerships. 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 majority 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 In order to meet the Company’s capital requirements, cash from external sources must periodically be obtained through short-term bank loans and commercial paper, as well as through issuances of long- term debt and equity securities. The Company expects these traditional sources of cash to continue to supplement its internally generated cash during the next several years.* In February 1999, the Company issued $100.0 million of 6.0% medium-term notes due in March 2009. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $98.7 million. The proceeds of this debt issuance, together with other funds, were used to redeem $100.0 million of 5.58% medium-term notes which matured in March 1999. In July 1999, the Company issued $100.0 million of 6.82% medium-term notes due to mature in August 2004. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $99.5 million. The proceeds of this debt issuance, together with other funds, were used to redeem $50.0 million of 7.25% medium-term notes which matured in July 1999 and to complete the redemption of HarCor’s 14.875% senior secured notes, discussed below. In March and July of 1999, the Company redeemed HarCor’s 14.875% senior secured notes. The Company redeemed the notes at a redemption price of 110% of face value, which amounted to $59.1 million. The senior secured notes were recorded at fair market value on the opening balance sheet in 1998 to reflect an effective interest rate of 5.875% and the projected redemption of this debt in 1999. The Company’s embedded cost of long-term debt was 7.0% and 6.9% at September 30, 1999 and 1998, respectively. Consolidated short-term debt increased $67.2 million during 1999. The Company continues to consider short-term bank loans and commercial paper important sources of cash for temporarily financing capital expenditures and investments in corporations and/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 March 1998, the Company obtained authorization from the SEC, under the Holding Company Act, to issue long-term debt securities and equity securities in amounts not exceeding $2.0 billion during the order’s authorization period, which extends to December 31, 2002. In August 1999, the Company obtained authorization from the SEC under the Securities Act of 1933 to issue up to $625 million of debt and equity securities. 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, 1999, the Company would have been permitted to issue up to a maximum of $485.0 million in additional long-term unsecured indebt- edness at projected market interest rates. In addition, at September 30, 1999, the Company had regu- latory authorizations and unused short-term credit lines that would have permitted it to borrow an additional $356.5 million of short-term debt. N a t i o n a l F u e l G a s C o m p a n y 46 The amounts and timing of the issuance and sale of debt and/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 its business. In addition to the regulatory matters discussed in Note B - Regulatory Matters, in Item 8 of this report, 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 regula- tory matters could have a material effect on earnings and cash flows in the year of resolution, neither such litigation nor these other regulatory matters are expected to materially change the Company’s present liquidity position nor have a material adverse effect on the financial condition of the Company at this time.* M A R K E T R I S K S E N S I T I V E I N S T R U M E N T S Energy Commodity Price Risk Certain of the Company’s subsidiaries (primarily Seneca and NFR) utilize various derivative financial instruments (derivatives), including price swap agreements, options, exchange-traded futures and exchange-traded options, 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 fluc- tuations in the price of natural gas and crude oil, thereby providing more stability to operating results. The derivatives entered into by these subsidiaries are not held for trading purposes. These sub- sidiaries have operating procedures in place that are administered by experienced management to monitor compliance with their risk management policies. The following tables disclose natural gas and crude oil price swap information by expected matu- rity dates for agreements in which Seneca 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 (quan- tities) are used to calculate the contractual payments to be exchanged under the contract. The tables do not reflect the earnings impact of the physical transactions that are expected to offset the financial gains and losses arising from the use of the price swap agreements. The weighted average variable prices represent the prices as of September 30, 1999. At September 30, 1999, Seneca had not entered into any natural gas or crude oil price swap agreements extending beyond 2002. NATURAL GAS PRICE SWAP AGREEMENTS Notional Quantities (Equivalent Bcf) Weighted Average Fixed Rate (per Mcf) Weighted Average Variable Rate (per Mcf) CRUDE OIL PRICE SWAP AGREEMENTS Notional Quantities (Equivalent bbls) Weighted Average Fixed Rate (per bbl) Weighted Average Variable Rate (per bbl) Expected Maturity Dates 2 0 0 0 28.0 $2.70 $3.01 2 0 0 1 11.1 $2.66 $3.00 2 0 0 2 1.1 $2.61 $2.35 Total 40.2 $2.69 $2.99 Expected Maturity Dates 2 0 0 0 2 0 0 1 Total 2,112,000 $19.09 $23.79 184,000 $18.00 $23.79 2,296,000 $19.00 $23.79 N a t i o n a l F u e l G a s C o m p a n y 47 At September 30, 1999, Seneca would have had to pay the respective counterparties to its natural gas price swap agreements an aggregate of approximately $2.4 million to terminate the natural gas price swap agreements outstanding at that date. Seneca would have had to pay an aggregate of approx- imately $7.4 million to the counterparties to its crude oil price swap agreements to terminate the crude oil price swap agreements outstanding at September 30, 1999. The following tables disclose the notional quantities and weighted average strike prices for options utilized by Seneca to manage natural gas and crude oil price risk. The tables do not reflect the earnings impact of the physical transactions that are expected to offset any financial gains or losses that might arise if an option were to be exercised. WRITTEN CALL OPTIONS Crude Oil Notional Quantities (Equivalent bbls) Weighted Average Strike Price (per bbl) Natural Gas Notional Quantities (Equivalent Bcf) Weighted Average Strike Price (per Mcf) WRITTEN CALL OPTIONS(1) Crude Oil Notional Quantities (Equivalent bbls) Weighted Average Strike Price (per bbl) Natural Gas Notional Quantities (Equivalent Bcf) Weighted Average Strike Price (per Mcf) WRITTEN PUT OPTIONS Crude Oil Notional Quantities (Equivalent bbls) Weighted Average Strike Price (per bbl) PURCHASED CALL OPTION Crude Oil Notional Quantities (Equivalent bbls) Weighted Average Strike Price (per bbl) (1) The counterparty has a choice between a natural gas call option and a crude oil call option, depending on whichever option has greater value to the counterparty. Expected Maturity Date - 2 0 0 0 184,000 $18.00 2.6 $ 2.86 Expected Maturity Dates 2 0 0 0 2 0 0 1 Total 548,000 $18.00 10.4 $ 2.58 184,000 $18.00 3.5 $ 2.74 732,000 $18.00 13.9 $ 2.62 Expected Maturity Dates 2 0 0 0 2 0 0 1 Total 732,000 $12.50 184,000 $12.50 916,000 $12.50 Expected Maturity Date - 2 0 0 0 1,464,000 $20.00 At September 30, 1999, Seneca would have had to pay the counterparty to its call options $3.6 million on a net basis to terminate its call options. Seneca would have paid the counterparty $8.2 million related to the exercise of the written call and put options but would have received $4.6 million related to Seneca’s exercise of its purchased call option. N a t i o n a l F u e l G a s C o m p a n y 48 The Company is exposed to credit risk on the price swap agreements that Seneca has entered into as well as on the call options that Seneca has purchased. 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 does not anticipate any material impact to its financial position, results of operations, or cash flows as a result of nonperfor- mance by counterparties.* The following table discloses the net notional quantities, weighted average contract prices and weighted average settlement prices by expected maturity date for exchange-traded futures contracts uti- lized by NFR to manage natural gas price risk. The table does not reflect the earnings impact of the physical transactions that are expected to offset the financial gains and losses arising from the use of the futures contracts. At September 30, 1999, NFR held no futures contracts with maturity dates extending beyond 2001. EXCHANGE-TRADED FUTURES CONTRACTS Expected Maturity Dates Contract Volumes Purchased (Equivalent Bcf) Weighted Average Contract Price (per Mcf) Weighted Average Settlement Price (per Mcf) 2 0 0 0 2.0 $2.75 $2.89 2 0 0 1 0.1 $2.82 $2.98 Total 2.1 $2.75 $2.89 The following table discloses the notional quantities and weighted average strike prices by expected maturity dates for exchange-traded options utilized by NFR to manage natural gas price risk. The table does not reflect the earnings impact of the physical transactions that would offset any finan- cial gains or losses that might arise if an option were to be exercised. At September 30, 1999, NFR held no options with maturity dates extending beyond 2000. EXCHANGE-TRADED OPTIONS PURCHASED Notional Quantities (Equivalent Bcf) Weighted Average Strike Price (per Mcf) EXCHANGE-TRADED OPTIONS SOLD Notional Quantities (Equivalent Bcf) Weighted Average Strike Price (per Mcf) Expected Maturity Date - 2 0 0 0 9.0 $2.72 Expected Maturity Date - 2 0 0 0 17.1 $3.01 At September 30, 1999, NFR would have received approximately $2.3 million to settle the exchange- traded futures outstanding at that date. NFR would have paid approximately $1.2 million to settle its exchange-traded options outstanding at September 30, 1999. Exchange Rate Risk Horizon’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. During 1999, the Czech koruna decreased in value in relation to the U.S. dollar resulting in a $11.7 million negative adjustment to the Cumulative Foreign Currency Translation Adjustment (a component of Accumulated Other Comprehensive Income). Further valuation changes to the Czech koruna would result in corresponding positive or negative adjustments to the Cumulative Foreign Currency Translation Adjustment. Management cannot predict whether the Czech koruna will increase or decrease in value against the U.S. dollar.* N a t i o n a l F u e l G a s C o m p a n y 49 Interest Rate Risk The Company’s exposure to interest rate risk primarily consists of short-term debt instruments. At September 30, 1999, these instruments included short-term bank loans and commercial paper totaling $392.3 million (domestically). The interest rate on these short-term bank loans and commercial paper approximated 5.5%. These instruments also included $1.2 million of short-term bank loans held by SCT in the Czech Republic at September 30, 1999. The interest rate on the Czech Republic loans approximated 6.4%. 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, 1999: (Millions of Dollars) 2 0 0 0 2 0 0 1 2 0 0 2 2 0 0 3 2 0 0 4 Thereafter Total Principal Amounts by Expected Maturity Dates National Fuel Gas Company Long-Term Fixed Rate Debt Weighted Average Interest Rate Paid Fair Value = $798.7 million PSZT Long-Term Variable Rate Debt Weighted Average Interest Rate Paid Fair Value = $47.7 million Other Notes Long-Term Debt(1) Weighted Average Interest Rate Paid Fair Value = $20.7 million $ 50 6.6% $ — —% $ — —% $ — —% $225 7.3% $549 6.6% $ 824 6.8% $ 7.2 7.5% $9.5 7.5% $9.5 7.5% $9.5 7.5% $ 9.5 7.5% $ 2.5 7.5% $47.7 7.5% $12.4 11.3% $3.1 6.7% $1.2 6.7% $0.9 7.3% $ 0.9 7.3% $ 2.2 6.8% $20.7 9.5% (1) $5.8 million is variable rate debt; $14.9 million is fixed rate debt. PSZT utilizes an interest rate swap to eliminate interest rate fluctuations on its CZK 1,595,924,000 term loan ($47.7 million at September 30, 1999), 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 2001, PSZT pays a fixed rate of 8.31% and receives a floating rate of six month PRIBOR. PSZT would have paid approximately $1.0 million to settle the interest rate swap at September 30, 1999. R AT E M AT T E R S New York Jurisdiction On October 21, 1998, the NYPSC approved a rate plan for Distribution Corporation for the period beginning October 1, 1998 and ending September 30, 2000. The plan was the result of a settlement agreement entered into by Distribution Corporation, Staff for the NYPSC (Staff), Multiple Intervenors (an advocate for large industrial customers) and the State Consumer Protection Board. Under the plan, Distribution Corporation’s rates were reduced by $7.2 million, or 1.1%. In addition, customers are receiving up to $6.0 million in bill credits, disbursed volumetrically over the two year term, reflect- ing a predetermined share of excess earnings under a 1996 settlement. An allowed return on equity of 12%, above which additional earnings will be shared equally with the customers, was maintained from Utility Operation N a t i o n a l F u e l G a s C o m p a n y 50 a 1996 settlement. Finally, as provided by the rate plan, $7.2 million of 1999 revenues were set aside in a special reserve to be applied against Distribution Corporation’s incremental costs resulting from the NYPSC’s gas restructuring effort further described below. 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 competi- tive 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 partici- pants 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 compe- tition; 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 hopes to accomplish that objective over a three-to-seven year transition period, 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 ses- sions 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. Distribution Corporation was recently advised, on an informal basis, that its “individualized plan” for restructuring to “effectuate [the NYPSC’s] vision” may be included in discussions anticipated in connection with the current rate settlement, which expires on its own terms on September 30, 2000. On June 7, 1999, the NYPSC issued a notice requesting comments on Staff’s proposal for a “single retailer” billing environment. The proposal recommends that electric and gas utilities exit the billing function at an undetermined future date. The retail billing function would then be performed solely by unregulated marketers. Included in the billing proposal is a recommendation that utilities design a “back-out” credit equal to the long run costs avoided by each utility when billing is provided by another party. Distribution Corporation filed comments opposing much of the proposal but sup- porting a suggested interim regime where multiple billing arrangements, including utility billing, would be permitted. This proceeding remains pending. In anticipation of a NYPSC order partially adopting Staff’s recommendation, Distribution Corporation is exploring the development of a retail billing service for sale to marketers serving aggregated customers. There is a market for retail billing services in Distribution Corporation’s service territory, and Distribution Corporation believes that a service can be designed that will meet the approval of the regulators.* N a t i o n a l F u e l G a s C o m p a n y 51 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. Effective October 1, 1997, Distribution Corporation commenced a PaPUC approved customer choice pilot program called Energy Select. Energy Select, which lasted until April 1, 1999, allowed approximately 19,000 small commercial and residential customers of Distribution Corporation in the greater Sharon, Pennsylvania area to purchase gas supplies from qualified, participating non-utility suppliers (or marketers) of gas. Distribution Corporation was not a supplier of gas in this pilot. Under Energy Select, Distribution Corporation delivered the gas to the customer’s home or business and remained responsible for reading customer meters, the safety and maintenance of its pipeline system and responding to gas emergencies. NFR was a participating supplier in Energy Select. Effective February 11, 1999, Distribution Corporation’s System Wide Energy Select tariff was approved by the PaPUC. This program is intended to expand the Energy Select pilot program described above to apply across Distribution Corporation’s entire Pennsylvania service territory. The plan borrows many features of the Energy Select pilot, but several important changes were adopted. Most significantly, the new program includes Distribution Corporation as a choice for retail con- sumers, in furtherance of Distribution Corporation’s objective to remain a merchant. Also departing from the pilot scheme, Distribution Corporation resumes its role as provider of last resort and main- tains customer contact by providing a billing service on its own behalf and, as an option, for participat- ing marketers. 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 compliance filing on October 1, 1999 for an effective date on or about July 1, 2000. The filing largely mirrors the Energy Select program currently in effect, which substantially complies with the Act’s requirements. Currently the parties to the proceeding are engaged in routine discovery and settlement discussions have begun. Distribution Corporation is unable to predict the outcome of the proceeding at this time. 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. Pipeline and Storage Supply Corporation currently does not have a rate case on file with the Federal Energy Regulatory Commission (FERC). Its last case was settled with the FERC in February 1996. As part of that settle- ment, Supply Corporation agreed not to seek recovery of revenues related to certain terminated service from storage customers until April 1, 2000, as long as the terminations were not greater than approximately 30% of the terminable service. Supply Corporation has been successful in marketing and obtaining executed contracts for such terminated storage service (at discounted rates) and expects to continue obtaining executed contracts for additional terminated storage service as it arises.* N a t i o n a l F u e l G a s C o m p a n y 52 Environmental Matters New Accounting Pronouncements Year 2000 O T H E R M AT T E R S It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remedi- ation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. Distribution Corporation and Supply Corporation have estimated their clean-up costs related to former manufactured gas plant and former gasoline plant sites and third party waste disposal sites will be in the range of $9.4 million to $10.4 million.* The minimum liability of $9.4 million has been recorded on the Consolidated Balance Sheet at September 30, 1999. 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 pro- tection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory policies and pro- cedures. For further discussion refer to Note H - Commitments and Contingencies under the heading “Environmental Matters” in Item 8 of this report. 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). In June 1999, the FASB issued SFAS 137, “Accounting for Derivative Instruments and Hedging Activities – Deferral of the Effective Date of SFAS 133.” For a discussion of SFAS 133 and SFAS 137 and their impact on the Company, see disclosure in Note A - Summary of Significant Accounting Policies in Item 8 of this report. Numerous media reports have heightened concern that information technology computer systems, software programs and semiconductors may not be capable of recognizing dates after the Year 2000 because such systems use only two digits to refer to a particular year. Such systems may read dates in the Year 2000 and thereafter as if those dates represent the year 1900 or thereafter and, in certain instances, such systems may fail to function properly. State of Readiness The Company believes that all necessary work has been completed in order to make its internal com- puter system Year 2000 ready.* Following the completion of an early-impact analysis study, a formal project manager at the Company was designated to spearhead the Year 2000 remediation effort. The methodology adopted by the Company to address the Year 2000 issue is a combination of methods recommended by respected industry consultants and efforts tailored to meet the Company’s specific needs. The Company’s Year 2000 plan addresses five primary areas. A. Mainframe Corporate Business Applications Developed and Maintained by the Company: A detailed plan and impact analysis was conducted in 1996-1997 to determine the extent of Year 2000 implica- tions on the Company’s mainframe-based computer systems. The remediation and testing in this area have been completed.* N a t i o n a l F u e l G a s C o m p a n y 53 B. Personal Computer Business Applications Software Developed and Supported by the Company: Distribution Corporation and Supply Corporation have retained a consulting firm to perform a detailed impact analysis of the personal computer business application systems supported by the Company’s Information Services Department. Seneca has similarly retained a consulting firm to review its Year 2000 issues. These firms have either corrected Year 2000 problems identified by their analysis or advised the respective subsidiaries of the potentially problematic computer applications. Certain applications identified by the consulting firms as potentially problematic have been retired and replaced with Year 2000 compliant applications. The required changes and testing for these appli- cations are complete.* C. Vendor-Supplied Software, Hardware, and Services for Corporate Business Applications Supported by the Company: This category includes all mainframe infrastructure products as well as all PC client/server software and hardware. The Company has sent letters to its vendors asking if their prod- ucts and services will continue to perform as expected after January 1, 2000. These vendors are responsible for approximately 200 products and services associated with corporate computer applica- tions. The Company has received responses from all vendors which the Company believes supply criti- cal hardware, software, date-sensitive embedded chips and related computer services. The Company has completed testing and implementation of the vendor-supplied Year 2000 ready products and ser- vices.* D. Vendor-Supplied Products and Services Used on a Corporate Wide Basis: This category includes the critical products and services that are used by multiple departments within the Company including all products containing embedded chips which might be date sensitive. The Company has sent letters to the primary vendors who provide these products and services to the Company, requesting Year 2000 compliance plans. The Company is monitoring their responses and has incorporated them into the Company’s overall Year 2000 project and contingency plans. The Company has completed testing and implementation of the products and services of these vendors (reference is made to the “Risks” section below).* E. User-Department Maintained Business Applications: The Company uses certain business software applications that were either built in-house or vendor-supplied and subsequently maintained by indi- vidual departments of the Company. The scope of such applications includes, but is not limited to, spreadsheets, databases, vendor provided products and services and embedded process controls. A cor- porate wide Year 2000 task force is in place and has established a process to identify and resolve Year 2000 problems in this area. This task force meets on a monthly basis to coordinate ongoing activities and report on the project status. Providers of critical products and services have been identified and the Company has sent letters requesting their Year 2000 compliance plans. Responses are being moni- tored and incorporated into the Year 2000 planning of the various departments. Based on responses received to date along with internal testing, the Company believes that all applications and services under this category are Year 2000 ready.* Cost The cost of upgrading both vendor supplied and internally developed systems and services is expensed as incurred and has amounted to approximately $2.3 million in total. Minimal additional expenses related to Year 2000 administration are expected to be incurred.* Risks The Company’s main concern is to ensure the safe, reliable and uninterrupted production and deliv- ery of natural gas and Company-provided services to its customers. Based on the efforts discussed above, the Company expects to be able to operate its own facilities without interruption and continue normal operation in Year 2000 and beyond.* However, the Company has no control over the systems and services used by third parties with whom it interfaces. While the Company has placed its major N a t i o n a l F u e l G a s C o m p a n y 54 third parties on notice that the Company expects their products and services to perform as expected after January 1, 2000, the Company cannot predict with accuracy the actual adverse consequences to the Company that could result if such third parties are not Year 2000 compliant.* The widespread failure of electric, telecommunication, and upstream gas supply could potentially affect gas service to utility customers, and the Company is pursuing contingency plans to avoid such disruptions.* The majority of the devices which control the Company’s physical delivery system are not believed to be susceptible to Year 2000 problems because they do not contain micro-processors. The Company has conducted an extensive review of its existing micro-processors (embedded technology) and has replaced non-Year 2000 compliant hardware. Distribution Corporation is subject to regulatory review by both the NYPSC and the PaPUC. Both of these regulatory bodies have issued orders concerning the Year 2000 issue, and both have established dates in 1999 by which jurisdictional utilities must have taken the necessary steps to ensure that its critical systems are Year 2000 ready. Distribution Corporation has, to date, met the requirements of those orders and will continue to comply with such orders for the pertinent time periods specified in such orders.* Contingency Planning The Company formed its Corporate Year 2000 task force in mid-1997. The primary function of this group was, and continues to be, to: (1) raise awareness of the Year 2000 issue within the Company, (2) facilitate identification and remediation of Year 2000 potential problems within the Company, and (3) facilitate and develop corporate contingency plans. The group is comprised of middle to senior level managers and Company executives. The Company has developed Year 2000 strategic contingency plans which have been prioritized in relation to the overall corporation in the order of human safety, reliability/delivery of Company services and administrative services. The Company has added the operational specifics to these plans and is continuing to hone them through operational drills. During September through November 1999, Distribution Corporation and Supply Corporation conducted Year 2000 Readiness Drills at critical Company owned operating facilities (e.g. compressor stations, pipeline interconnect locations, and gas dispatching control centers) to simulate operation under the low probability occurrence of loss of local electricity or communications (primarily telephone). These drills tested backup generation equipment, alternative communication functionality (radios), and our employees’ preparedness to manually operate the physical gas delivery system should these low proba- bility events occur. These drills also tested and sharpened the Company’s readiness to dispatch and make safe any customer emergencies, which might occur during a loss of electrical supply or commu- nications functionality. The Company will have a very significant incremental workforce in the field during the critical Year 2000 rollover period New Year’s Eve. The pertinent portions of these plans have been filed with the NYPSC whose review is ongoing. Distribution Corporation and Supply Corporation are currently working with other utilities in their service areas and regional Emergency Management Services to establish communication channels and procedures in the low probability event of a serious Year 2000 disruption. The Company has always had disaster/contingency plans to deal with operational gas supply or delivery problems, loss of the corporate data center, and loss of the corporate customer telephone centers. These plans, in conjunction with the Year 2000 drills, enable the Company to verify its readiness and ability to operate in the event of failures resulting from Year 2000 problems arising outside of the Company (i.e., loss of electricity, telephone service, etc.). All crit- ical Year 2000 contingency plans have been completed.* All of the above Year 2000 information is a YEAR 2000 READINESS DISCLOSURE made pur- suant to the Year 2000 Information and Readiness Disclosure Act of 1998. N a t i o n a l F u e l G a s C o m p a n y 55 Effects of Inflation Although the rate of inflation has been relatively low over the past few years, and thus has benefited both the Company and its customers, 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. Safe Harbor for Forward-Looking Statements 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, 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 available 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 cautionary statements. Certain statements contained herein, includ- ing 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 his- torical 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 and/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 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 unanticipated project delays; 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; 11. Ability to successfully identify and finance oil and gas property acquisitions and ability to operate existing and any subsequently acquired properties; 12. Ability to successfully identify, drill for and produce economically viable natural gas and oil reserves; 13. Changes in the availability and/or price of derivative financial instruments; 14. Inability of the various counterparties to meet their obligations with respect to the Company’s financial instruments; N a t i o n a l F u e l G a s C o m p a n y 56 15. Regarding foreign operations - changes in foreign trade and monetary policies, laws and regula- tions related to foreign operations, political and governmental changes, inflation and exchange rates, taxes and operating conditions; 16. Significant changes in tax rates or policies or in rates of inflation or interest; 17. Significant changes in the Company’s relationship with its employees and the potential adverse effects if labor disputes or grievances were to occur; 18. Changes in accounting principles and/or the application of such principles to the Company; and/or 19. Unanticipated problems related to the Company’s internal Year 2000 initiative as well as potential adverse consequences related to third party Year 2000 compliance. 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 Refer to the “Market Risk Sensitive Instruments” section in Item 7, MD&A. I T E M 8 Financial Statements and Supplementary Data Index to Financial Statements Financial Statements: Report of Independent Accountants 58 Consolidated Statements of Income and Earnings Reinvested in the Business, three years ended September 30, 1999 59 Consolidated Balance Sheets at September 30, 1999 and 1998 60 Consolidated Statement of Cash Flows, three years ended September 30, 1999 62 Consolidated Statement of Comprehensive Income, three years ended September 30, 1999 63 Notes to Consolidated Financial Statements 64 Financial Statement Schedules: For the three years ended September 30, 1999 II-Valuation and Qualifying Accounts 88 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 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 refer- ence is made thereto. N a t i o n a l F u e l G a s C o m p a n y 57 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 princi- ples and necessarily include some amounts that are based on management’s best estimates and judg- ment. 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 manage- ment’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, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 1999, in conformity with accounting principles gener- ally accepted in the United States. In addition, in our opinion, the financial statement schedules listed in the accompanying index present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial state- ments and financial statement schedules are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits of these statements in accordance with auditing stan- dards generally accepted in the United States, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by man- agement, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. As discussed in Note A to the consolidated financial statements, the Company changed its method of depletion for oil and gas properties in 1998. PricewaterhouseCoopers LLP Buffalo, New York October 25, 1999 N a t i o n a l F u e l G a s C o m p a n y 58 C O N S O L I D AT E D S TAT E M E N T S O F I N C O M E A N D E A R N I N G S R E I N V E S T E D I N T H E B U S I N E S S Year Ended September 30 (Thousands of Dollars, Except Per Common Share Amounts) 1 9 9 9 1 9 9 8 1 9 9 7 INCOME Operating Revenues $1,263,274 $1,248,000 $1,265,812 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 EARNINGS REINVESTED Balance at Beginning of Year IN THE BUSINESS 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 N a t i o n a l F u e l G a s C o m p a n y 59 405,925 55,788 300,007 23,881 91,146 129,690 – 64,829 441,746 37,837 293,976 25,793 92,817 118,880 128,996 24,024 528,610 1,489 260,839 25,698 100,549 111,650 — 68,674 1,071,266 1,164,069 1,097,509 192,008 12,343 83,931 35,870 168,303 3,196 204,351 119,801 171,499 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 42,131 14,680 56,811 — 114,688 — 114,688 422,874 537,562 64,967 $472,517 $428,112 $472,595 $2.98 – $2.98 $2.95 – $2.95 $0.85 (0.24) $0.61 $0.84 (0.24) $0.60 $3.01 — $3.01 $2.98 — $2.98 38,663,981 39,041,728 38,316,397 38,703,526 38,083,514 38,440,018 C O N S O L I D AT E D B A L A N C E S H E E T S At September 30 (Thousands of Dollars) 1 9 9 9 1 9 9 8 ASSETS Property, Plant and Equipment Less - Accumulated Depreciation, Depletion and Amortization $3,383,537 1,029,643 $3,186,853 938,716 2,353,894 2,248,137 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 29,222 105,296 18,674 41,099 23,350 4,576 35,072 257,289 30,437 82,336 15,403 31,661 24,609 6,316 19,755 210,517 87,724 21,717 25,214 14,266 82,482 88,303 22,295 41,735 8,619 64,853 231,403 225,805 $2,842,586 $2,684,459 N a t i o n a l F u e l G a s C o m p a n y 60 At September 30 (Thousands of Dollars) 1 9 9 9 1 9 9 8 CAPITALIZATION AND LIABILITIES Capitalization: Common Stock Equity Common Stock, $1 Par Value Authorized – 200,000,000 Shares; Issued and Outstanding – 38,837,499 Shares and 38,468,795 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 $ 38,837 431,952 472,517 (4,013) 939,293 822,743 $ 38,469 416,239 428,112 7,265 890,085 693,021 1,762,036 1,583,106 27,589 25,479 393,495 69,608 82,747 5,934 87,310 639,094 275,008 14,814 11,007 113,038 413,867 – 326,300 216,929 59,933 5,781 80,480 689,423 258,222 18,404 11,372 98,453 386,451 — $2,842,586 $2,684,459 N a t i o n a l F u e l G a s C o m p a n y 61 OPERATING ACTIVITIES INVESTING ACTIVITIES FINANCING ACTIVITIES C O N S O L I D AT E D S TAT E M E N T O F C A S H F L O W S Year Ended September 30 (Thousands of Dollars) 1 9 9 9 1 9 9 8 1 9 9 7 Net Income Available for Common Stock Adjustments to Reconcile Net Income to Net Cash 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 $115,037 $23,188 $114,688 – – 129,690 14,030 1,616 7,018 9,116 128,996 118,880 (26,237) 2,213 (6,378) — — 111,650 3,800 — 8,030 (18,161) 45,200 (10,332) (7,806) 1,740 (15,322) 22,871 153 10,931 (906) 10,999 (1,271) (6,316) 829 (24,975) (4,735) (15,481) 36 9,913 7,300 — 10,065 9,495 5,898 4,113 (2,856) 32,811 Net Cash Provided by Operating Activities 271,890 252,978 294,662 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 Cash and Temporary Cash Investments at End of Year See Notes to Consolidated Financial Statements (260,506) (5,774) (3,633) 6,687 (393,233) (111,966) (5,453) 7,583 (214,001) (21,075) — 1,429 (263,226) (503,069) (233,647) 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 (107,300) 99,500 (1,310) 7,074 (64,260) — (66,296) — (1,215) 16,398 (5,281) 30,437 $29,222 14,039 $30,437 19,320 $14,039 N a t i o n a l F u e l G a s C o m p a n y 62 C O N S O L I D AT E D S TAT E M E N T O F C O M P R E H E N S I V E I N C O M E Year Ended September 30 (Thousands of Dollars) 1 9 9 9 1 9 9 8 1 9 9 7 Net Income Available for Common Stock $115,037 $23,188 $114,688 Other Comprehensive Income (Loss), Before Tax: Foreign Currency Translation Adjustment Unrealized Gain on Securities Available for Sale Other Comprehensive Income (Loss), Before Tax Income Tax Expense Related to Unrealized Gain on Securities Available for Sale Other Comprehensive Income (Loss), Net of Tax (11,737) 706 (11,031) 247 (11,278) 9,350 — 9,350 — 9,350 (2,085) — (2,085) — (2,085) Comprehensive Income $103,759 $32,538 $112,603 See Notes to Consolidated Financial Statements N a t i o n a l F u e l G a s C o m p a n y 63 N O T E S T O C O N S O L I D AT E D F I N A N C I A L S TAT E M E N T S N O T E A Summary of Significant Accounting Policies Principles of Consolidation The consolidated financial statements include the accounts of the Company and its majority owned subsidiaries. The equity method is used to account for the Company’s investment in any minority owned entities. All significant intercompany balances and transactions have been eliminated where appropriate. The preparation of the consolidated financial statements in conformity with generally accepted accounting 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 Two of the Company’s principal subsidiaries, Distribution Corporation and Supply Corporation, are subject to regulation by certain state and federal authorities. Distribution Corporation and Supply Corporation have 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 regulation 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 fur- nished. Unrecovered Purchased Gas Costs and Refunds Distribution Corporation’s rate schedules 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. Distribution Corporation’s rate settlements with the State of New York Public Service Commission (NYPSC) include provisions for a sharing of earnings over a specified rate of return on equity. Estimated refund liabilities are recorded over the term of the settlements which reflect man- agement’s current estimate of such refunds. Reference is made to Note B - Regulatory Matters for further discussion. Property, Plant and Equipment The principal assets, 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. N a t i o n a l F u e l G a s C o m p a n y 64 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. 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, Seneca’s capitalized costs under the full-cost method of accounting exceeded these limits at March 31, 1998. Seneca was required to recognize an impairment of its oil and gas producing 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. 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 percentage of average depreciable prop- erty, were 4.3% in 1999, 4.4% in 1998 and 4.6% in 1997. Cumulative Effect of Change in Accounting Effective October 1, 1997, Seneca 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 cumula- tive effect reduced earnings for 1998 by $9.1 million, net of income tax. Depletion of oil and gas prop- erties for 1999 and 1998 was computed under the units of production method. Pro forma amounts for 1998 and 1997 shown below, assume the retroactive application of the new depletion method. 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 1 9 9 8 1 9 9 7 $23,188 $32,304 $114,688 $113,022 $0.61 $0.85 $0.60 $0.84 $3.01 $2.97 $2.98 $2.94 Gas Stored Underground - Current Gas stored underground - current 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 1999, 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 $51.4 million at September 30, 1999. N a t i o n a l F u e l G a s C o m p a n y 65 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 sub- sidiaries 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. The translation from the local currency to U.S. dollars is performed for balance sheet accounts by using current exchange ratios in effect at the balance sheet date and, for revenue and expense accounts, by using an average exchange rate during the period. The resultant cumulative foreign currency translation adjust- ment is recorded as a component of Accumulated Other Comprehensive Income in the Common Stock Equity section of the Consolidated Balance Sheet. 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. Financial Instruments Unrealized gains or losses from “available-for-sale securities” (i.e., the Company’s investments in mar- ketable equity securities) are recorded as a component of Accumulated Other Comprehensive Income in the Common Stock Equity section of the Consolidated Balance Sheet. Reference is made to Note F - Financial Instruments for further discussion. Seneca utilizes price swap agreements and options (primarily written options) to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil. NFR utilizes exchange-traded futures and exchange-traded options to manage a portion of the market risk that it faces due to fluctuations in the price of natural gas. Gains or losses from Seneca’s price swap agreements are accrued in operating revenues on the Consolidated Statement of Income at the con- tract settlement dates. Seneca’s options are marked-to-market on a quarterly basis with gains or losses recorded in Operating Revenues on the Consolidated Statement of Income. Gains or losses from NFR’s exchange-traded futures and exchange-traded options are recorded in Other Deferred Credits on the Consolidated Balance Sheet until the hedged commodity transaction occurs, at which point they are reflected in operating revenues on the Consolidated Statement of Income. Reference is made to Note F - Financial Instruments for further discussion. In the International segment, PSZT utilizes an interest rate swap to eliminate interest rate fluctu- ations on its variable rate debt. Gains or losses are accrued in interest charges on the Consolidated Statement of Income at the contract settlement dates. N a t i o n a l F u e l G a s C o m p a n y 66 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. Interest paid in 1999, 1998 and 1997 was $75.8 million, $46.2 million and $52.4 million, respectively. Income taxes paid in 1999, 1998 and 1997 were $35.0 million, $64.5 million and $69.2 million, respectively. Details of the stock acquisitions made by the Company during 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 1 9 9 9 JTR(1) $13.5 (7.3) (0.4) (0.1) $ 5.7 1 9 9 8 SCT PSZT HarCor (2) Total $66.1 (22.3) (18.9) (6.3) $18.6 $141.8 (77.3) — (0.9) $ 63.6 $105.6 (73.0) — (2.8) $ 29.8 $313.5 (172.6) (18.9) (10.0) $112.0 (1) Jablonecká teplárenská a realitní, a.s. (JTR) is a majority owned subsidiary of SCT. (2) HarCor Energy, Inc. (HarCor). Further discussion of these acquisitions can be found at Note J - Stock Acquisitions. 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 outstanding 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. Accounting for Derivative Instruments and Hedging Activities 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). SFAS 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. This statement requires that an entity recognize all derivatives as either assets or liabilities in the statement of finan- cial 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. Management has evaluated the derivatives used by Seneca, NFR and Horizon and believes that the adoption of SFAS 133 will not have a material impact on the financial condition or results of oper- ations of the Company. Management is continuing to evaluate other financial instruments and con- tracts which may have embedded derivatives that could be impacted by the adoption of SFAS 133. SFAS 133 required the Company to adopt the standard in the first quarter of fiscal 2000. However, in June 1999, the FASB issued SFAS 137, “Accounting for Derivative Instruments and Hedging Activities – Deferral of the Effective Date of FASB Statement No. 133.” SFAS 137 delays, by one year, the effective date of SFAS 133. Accordingly, the Company will adopt SFAS 133 by the first quarter of fiscal 2001. New Accounting Pronouncements N a t i o n a l F u e l G a s C o m p a n y 67 N O T E B Regulatory Matters Regulatory Assets and Liabilities Distribution Corporation and Supply Corporation have recorded the following regulatory assets and liabilities: At September 30 (Thousands) 1 9 9 9 1 9 9 8 Regulatory Assets: Recoverable Future Taxes (Note C) Unamortized Debt Expense (Note A) Pension and Post-Retirement Benefit Costs (Note G) Environmental Clean-up (Note H) 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. $87,724 15,223 21,217 — 3,997 128,161 5,934 18,913 14,814 26,087 3,226 68,974 $59,187 $88,303 16,886 22,483 12,394 6,858 146,924 5,781 19,341 18,404 20,222 1,741 65,489 $81,435 If for any reason Distribution Corporation and/or Supply Corporation ceases to meet the criteria for application of regulatory accounting treatment 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 services provided in New York, Distribution Corporation has entered into rate settle- ments with the NYPSC. The rate settlements provide for a sharing mechanism, whereby earnings above a 12% return on equity are to be shared equally between shareholders and ratepayers. As a result of this sharing mechanism, Distribution Corporation had liabilities of $8.6 million and $10.7 million at September 30, 1999 and 1998, respectively. Of these amounts, $3.0 million was reclassified to Amounts Payable to Customers at September 30, 1999 and 1998 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 $7.4 million (including interest of $0.2 million) recorded during 1999 to be applied against Distribution Corporation’s incremental costs resulting from the NYPSC’s gas restructuring effort and a “refund pool” of $3.5 million and $5.0 million at September 30, 1999 and 1998, 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 $2.5 million and $6.6 million at September 30, 1999 and 1998, respectively. N a t i o n a l F u e l G a s C o m p a n y 68 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 Total Income Taxes 1 9 9 9 1 9 9 8 1 9 9 7 $43,467 6,215 $40,740 6,635 $57,807 7,067 11,149 1,244 2,754 64,829 (729) (642) (21,687) (5,997) 4,333 24,024 (665) (1,218) 2,895 905 — 68,674 (665) — — $63,458 (5,737) $16,404 — $68,009 The U.S. and foreign components of income (loss) before income taxes are as follows: Year Ended September 30 (Thousands) 1 9 9 9 1 9 9 8 1 9 9 7 U.S. Foreign $169,037 9,457 $178,494 $ 31,127 8,465 $39,592 $184,257 (1,560) $182,697 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) 1 9 9 9 1 9 9 8 1 9 9 7 Net Income Available for Common Stock Income Tax Expense Income Before Income Taxes 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 $115,037 63,458 178,495 $23,188 16,404 39,592 $114,688 68,009 182,697 62,473 13,857 63,944 4,848 1,872 (833) (502) (1,362) (3,038) $ 63,458 986 2,186 (1,609) (774) 2,846 (1,088) $16,404 5,182 2,560 (1,320) (695) — (1,662) $ 68,009 N a t i o n a l F u e l G a s C o m p a n y 69 Significant components of the Company’s deferred tax liabilities and assets were as follows: Year Ended September 30 (Thousands) Deferred Tax Liabilities: Abandonments Accelerated Tax Depreciation Exploration and Intangible Well Drilling Costs Other Total Deferred Tax Liabilities Deferred Tax Assets: Capitalized Overheads Other Total Deferred Tax Assets Total Net Deferred Income Taxes 1 9 9 9 1 9 9 8 $ 21,192 132,732 165,798 62,565 382,287 (25,587) (81,692) (107,279) $275,008 $ 15,545 132,138 147,795 42,109 337,587 (22,484) (56,881) (79,365) $258,222 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 $14.8 million and $18.4 million at September 30, 1999 and 1998, 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 $87.7 million and $88.3 million at September 30, 1999 and 1998, respectively. The primary issues related to Internal Revenue Service audits of the Company for the years 1977- 1994 were settled during March 1998 and the remaining issues were settled in December 1998. Net income for the years ended September 30, 1999 and 1998 was increased by approximately $3.9 million and $5.0 million, respectively, as a result of interest, net of tax and other adjustments, related to these settlements. N a t i o n a l F u e l G a s C o m p a n y 70 N O T E D Capitalization SUMMARY OF CHANGES IN COMMON STOCK EQUITY (Thousands, Except Per Share Amounts) Balance at September 30, 1996 Net Income Available for Common Stock Dividends Declared on Common Stock ($1.71 Per Share) Other Comprehensive Income, Net of Tax Common Stock Issued Under Stock and Benefit Plans 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 Common Stock Shares Amount Paid In Capital Earnings Reinvested in the Business Accumulated Other Comprehensive Income 37,852 $37,852 $395,272 314 38,166 314 38,166 9,756 405,028 303 38,469 303 38,469 11,211 416,239 368 368 15,713 $ 422,874 114,688 (64,967) 472,595 23,188 (67,671) 428,112 115,037 (70,632) $ — (2,085) (2,085) 9,350 7,265 (11,278) Balance at September 30, 1999 38,837 $38,837 $431,952 $472,517(1) $(4,013) (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, 1999, $398.1 million of accumulated earnings was free of such limitations. Common Stock The Company has various plans which allow shareholders, customers and employees to purchase shares of Company common stock. The Dividend Reinvestment and Stock Purchase Plan allows share- holders to reinvest cash dividends and/or make cash investments in the Company’s common stock. The Customer Stock Purchase Plan 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. Effective November 1, 1999, these two plans were combined into a new plan, known as the National Fuel Direct Stock Purchase and Dividend Reinvestment Plan. 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. N a t i o n a l F u e l G a s C o m p a n y 71 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 represent- ing the outstanding 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 acquiring, 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 owner- ship 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 adjust- ments. 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. N a t i o n a l F u e l G a s C o m p a n y 72 For the years ended September 30, 1999, 1998 and 1997, no compensation expense was recog- nized for options granted under these plans. Compensation expense related to stock appreciation rights and restricted stock under these stock plans was $1.0 million, $4.1 million and $8.1 million for the years ended September 30, 1999, 1998 and 1997, respectively. 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 1 9 9 9 1 9 9 8 1 9 9 7 $115,037 $111,385 $23,188 $18,859 $114,688 $110,506 $2.98 $2.88 $2.95 $2.85 $0.61 $0.49 $0.60 $0.49 $3.01 $2.90 $2.98 $2.87 Transactions involving option shares for all plans are summarized as follows: Outstanding at September 30, 1996 Granted in 1997 Exercised in 1997(1) Forfeited in 1997 Outstanding at September 30, 1997 Granted in 1998 Exercised in 1998(1) Forfeited in 1998 Outstanding at September 30, 1998 Granted in 1999 Exercised in 1999(1) Forfeited in 1999 Outstanding at September 30, 1999 Option shares exercisable at September 30, 1999 Option shares available for future grant at September 30, 1999(2) Number of Shares Subject to Option Weighted Average Exercise Price 1,773,251 678,750 (274,655) (3,000) 2,174,346 770,000 (205,200) (7,250) 2,731,896 753,400 (111,504) (9,700) 3,364,092 2,537,360 76,338 $29.62 $39.61 $25.80 $36.81 $33.21 $44.44 $ 27.41 $41.68 $36.79 $46.70 $28.41 $37.41 $39.29 $37.01 (1) In connection with exercising these options, 16,531, 44,580 and 117,326 shares were surrendered and canceled during 1999, 1998 and 1997, respectively. (2) Including shares available for restricted stock grants. The weighted average fair value per share of options granted in 1999, 1998 and 1997 was $7.43, $7.91 and $7.66, respectively. These weighted average fair values were estimated on the date of grant using a binomial 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 1 9 9 9 1 9 9 8 1 9 9 7 0.97% 18.86% 4.74% 5.0 0.98% 16.48% 5.77% 5.5 1.06% 16.76% 6.58% 5.0 N a t i o n a l F u e l G a s C o m p a n y 73 The following table summarizes information about options outstanding at September 30, 1999: Options Outstanding Options Exercisable Range of Exercise Price Number Outstanding at 9/30/99 Weighted Average Remaining Contractual Life $23.81 – $35.72 $35.73 – $49.57 846,817 2,517,275 4.5 years 8.2 years Weighted Average Exercise Price $28.77 $42.83 Number Exercisable at 9/30/99 846,817 1,690,543 Weighted Average Exercise Price $28.77 $41.14 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 1 9 9 9 1 9 9 8 1 9 9 7 Shares of Restricted Stock Awarded Weighted Average Market Price of Stock on Award Date 6,580 $46.06 7,609 $44.88 6,300 $40.88 As of September 30, 1999, 96,319 shares of non-vested restricted stock were outstanding. Vesting restrictions will lapse as follows: 2000 - 28,216 shares; 2001 - 35,103 shares; 2002 - 8,000 shares; 2003 - 8,000 shares; 2004 - 7,000 shares; 2005 - 6,000 shares; and 2006 - 4,000 shares. Redeemable Preferred Stock As of September 30, 1999, there were 10,000,000 shares of $1 par value Preferred Stock authorized but unissued. 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: 5.58% to 8.48% due March 1999 to August 2027(1) HarCor: 14.875% Senior Secured Notes PSZT: 8.04% U.S. Dollar Denominated Debt due March 2000 - December 2004(2) 7.505% Term Loan due March 2000 – December 2004(2) Other Notes Total Long-Term Debt Less Current Portion 1 9 9 9 1 9 9 8 $125,000 $125,000 699,000 824,000 649,000 774,000 — 62,571 — 47,671 47,671 20,680 892,351 69,608 $822,743 50,596 — 50,596 22,783 909,950 216,929 $693,021 (1) Includes $50 million of 8.48% medium-term notes due July 2024 which are callable at a redemption price of 106.36% through July 2000. 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. (2) In December 1998, PSZT converted its U.S. Dollar denominated debt to a Czech koruna denominated term loan. The interest rate on the new term loan is six month Prague Interbank Offered Rate (PRIBOR) plus 0.475%. Refer to Note F – Financial Instruments for discussion of PSZT’s interest rate swap. N a t i o n a l F u e l G a s C o m p a n y 74 The aggregate principal amounts of long-term debt maturing for the next five years and thereafter are as follows: $69.6 million in 2000, $12.6 million in 2001, $10.7 million in 2002, $10.4 million in 2003, $235.4 million in 2004 and $553.7 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 discre- tionary 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, 1999, the Company had outstanding short-term notes payable to banks and commercial paper of $246.0 million (domestic = $244.8 million; foreign = $1.2 million) and $147.5 million, respectively. At September 30, 1998, the Company had outstanding notes payable to banks and commercial paper of $196.3 million and $130.0 million, respectively. The weighted average interest rate on domestic notes payable to banks was 5.55% and 5.67% at September 30, 1999 and 1998, respectively. The interest rate on the foreign notes payable to banks was 6.35% at September 30, 1999. There were not any foreign notes payable to banks at September 30, 1998. The weighted average interest rate on commercial paper was 5.49% and 5.60% at September 30, 1999 and 1998, respectively. 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 criteria, the fair market value of long-term debt, including current portion, was as follows: At September 30 (Thousands) Long-Term Debt 1 9 9 9 Carrying Amount 1 9 9 9 Fair Value 1 9 9 8 Carrying Amount 1 9 9 8 Fair Value $892,351 $867,056 $909,950 $966,437 The fair value amounts are not intended to reflect principal amounts that the Company will ulti- mately 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, as discussed below, are stated at fair value based on quoted market prices. Investments Other assets includes cash surrender values of insurance contracts and a mutual fund (accounted for as an “available-for-sale security”). The insurance contracts and mutual fund were established as an informal funding mechanism for various benefit obligations the Company has to certain employees. The cash surrender values of the insurance contracts amounted to $44.2 million and $40.1 million at September 30, 1999 and 1998, respectively. The mutual fund amounted to $5.0 million and $2.2 million at September 30, 1999 and 1998, respectively. N a t i o n a l F u e l G a s C o m p a n y 75 Other assets also includes shares of stock in an insurance company which the Company received as part of the insurance company’s initial public offering in 1999. This “demutualization” of the insurance company resulted in a gain to the Company of $2.4 million. At September 30, 1999, the value of the stock was $2.3 million. The stock is accounted for as an “available-for-sale security.” Derivative Financial Instruments Seneca has entered into certain price swap agreements and options to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil in an effort to provide more stability to its operating results. These agreements and options are not held for trading purposes. The price swap agreements call for Seneca to receive monthly payments from (or make payment 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 or a quoted natural gas price in “Inside FERC.” These variable prices are highly correlated with the market prices received by Seneca for its natural gas and crude oil production. The fair value of out- standing natural gas and crude oil price swap agreements and options discussed below reflect the esti- mated amounts Seneca would pay or receive to terminate its derivative financial instruments at September 30, 1999. At September 30, 1999, Seneca had natural gas price swap agreements covering a notional amount of 40.2 Bcf extending through 2002 at a weighted average fixed rate of $2.69 per Mcf. Seneca also had crude oil price swap agreements covering a notional amount of 2,296,000 bbls extending through 2001 at a weighted average fixed rate of $19.00 per bbl. The fair value of Seneca’s outstand- ing natural gas and crude oil price swap agreements at September 30, 1999 was a net loss of approxi- mately $9.8 million. This loss was offset by corresponding unrecognized gains from Seneca’s antici- pated natural gas and crude oil production over the terms of the price swap agreements. Seneca recognized net gains (losses) of $2.6 million, $(4.1) million and $(21.5) million related to settlements of its price swap agreements during 1999, 1998 and 1997, respectively. As the price swap agreements have been designated as hedges, these gains (losses) were offset by corresponding gains (losses) from Seneca’s natural gas and crude oil production. At September 30, 1999, Seneca had the following options outstanding: Type of Option Notional Amount Weighted Average Strike Price Written Call Option Written Call Option Written Call Options(1) Written Put Option Purchased Call Option 184,000 bbls 2.6Bcf 13.9 Bcf or 732,000 bbls 916,000 bbls 1,464,000 bbls $18.00/bbl $2.86/Mcf $2.62/Mcf or $18.00/bbl $12.50/bbl $20.00/bbl (1) The counterparty has a choice between a natural gas call option and a crude oil call option, depending on whichever option has greater value to the counterparty. As disclosed in Note A - Summary of Significant Accounting Policies, Seneca’s call and put options are being marked-to-market. The mark-to-market adjustment for 1999 was a loss of $1.3 million, the recording of which leaves the fair value of the call and put options at September 30, 1999 at a net loss of $3.6 million. During 1999, Seneca paid the counterparty $28,000 and $1.2 million related to the exercise of a portion of the written put options and the written call options, respectively. Seneca received $0.6 million from the counterparty related to Seneca’s exercise of a portion of the $20.00 per bbl call options that it had purchased. The Company is exposed to credit risk on the price swap agreements that Seneca has entered into as well as on the call options that Seneca has purchased. 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. N a t i o n a l F u e l G a s C o m p a n y 76 NFR utilizes exchange-traded futures and exchange-traded options to manage a portion of the market risk associated with fluctuations in the price of natural gas. Such futures and options are not held for trading purposes. At September 30, 1999, NFR had natural gas futures contracts covering 2.1 Bcf of gas on a net basis extending through 2001 at a weighted average contract price of $2.75 per Mcf. NFR had sold natural gas options covering 17.1 Bcf of gas at a weighted average strike price of $3.01 per Mcf. NFR also had purchased natural gas options covering 9.0 Bcf of gas at a weighted average strike price of $2.72 per Mcf. The exchange-traded futures and exchange-traded options are used to hedge NFR’s purchase and sale commitments and storage gas inventory. The fair value of NFR’s outstanding exchange-traded futures and exchange-traded options at September 30, 1999 was a net gain of approximately $1.1 million. This fair value reflects the estimated net amount that NFR would receive to terminate its exchange-traded futures and exchange-traded options at September 30, 1999. Since these exchange-traded futures contracts and exchange-traded options qualify and have been designated as hedges, any gains or losses resulting from market price changes would be substan- tially offset by the related commodity transaction. NFR recognized net gains (losses) of $(5.4) million, $1.3 million and $1.7 million related to futures contracts and options during 1999, 1998 and 1997, respectively. Since these futures contracts and options qualify and have been designated as hedges, these net gains (losses) were substantially offset by the related commodity transactions. PSZT utilizes an interest rate swap to eliminate interest rate fluctuations on its CZK 1,595,924,000 term loan ($47.7 million at September 30, 1999), which carries a variable interest rate of six month PRIBOR plus 0.475%. Under the terms of the interest rate swap, which extends until 2001, PSZT pays a fixed rate of 8.31% and receives a floating rate of six month PRIBOR. PSZT recog- nized a loss of $0.1 million related to this interest rate swap during 1999. The fair value of PSZT’s interest rate swap at September 30, 1999 was a loss of approximately $1.0 million. 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 and/or units in com- mingled funds or money market funds. Distribution Corporation and Supply Corporation are fully recovering their net periodic pension and post-retirement benefit costs in accordance with the applicable regulatory commission authoriza- tion. For financial reporting purposes, Distribution Corporation and Supply Corporation record the difference between the amounts of pension cost and post-retirement benefit cost recoverable in rates and the amounts of such costs as determined by their actuary under applicable accounting principles 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, N a t i o n a l F u e l G a s C o m p a n y 77 Distribution Corporation segregates the amount of such costs collected in rates, but not yet con- tributed 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 components of Net Periodic Benefit Cost and the Weighted Average Assumptions are as follows: Year Ended September 30 (Thousands) 1 9 9 9 1 9 9 8 1 9 9 7 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 Asset Recognition of Actuarial Loss Early Retirement Window Net Amortization and Deferral for Regulatory Purposes Net Periodic Benefit Cost $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) $432,753 9,988 33,532 1,479 10,336 (25,711) $462,377 $431,828 65,790 1,298 (25,711) $473,205 $ 10,828 (38,687) (22,296) 12,435 $ (37,720) 1 9 9 9 1 9 9 8 1 9 9 7 7.25% 8.50% 5.00% 7.00% 8.50% 5.00% 7.75% 8.50% 5.00% $12,676 36,299 (38,158) 1,012 (3,716) 2,833 7,032 2,721 $20,699 $10,655 35,485 (35,724) 1,065 (3,716) 981 — 4,829 $13,575 $9,988 33,532 (34,011) 991 (3,754) — 1,904 (374) $8,276 The effect of the discount rate change in 1999 was to decrease the Benefit Obligation by $15.9 million as of the end of the period. The effect of the discount rate change in 1998 was to increase the Benefit Obligation as of the end of the period by $45.0 million. N a t i o n a l F u e l G a s C o m p a n y 78 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) 1 9 9 9 1 9 9 8 1 9 9 7 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 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 Loss Net Amortization and Deferral for Regulatory Purposes Net Periodic Benefit Cost $ 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) $ 212,047 4,056 16,594 417 (6,653) (8,091) $ 218,370 $ 73,059 13,618 19,636 417 (8,091) $ 98,639 $(119,731) 505 114,034 $ (5,192) 1 9 9 9 1 9 9 8 1 9 9 7 7.25% 8.50% 5.00% 7.00% 8.50% 5.00% 7.75% 8.50% 5.00% $ 4,493 17,635 (10,134) 7,127 1,304 1,774 $22,199 $ 4,022 17,122 (8,099) 7,127 683 915 $21,770 $ 4,056 16,594 (6,014) 7,768 — (1,257) $21,147 The effect of the discount rate change in 1999 was to decrease the Benefit Obligation by $9.1 million. The effect of the discount rate change in 1998 was to increase the Benefit Obligation by $25.3 million. The annual rate of increase in the per capita cost of covered medical care benefits was assumed to be 10% for 1997, 9% for 1998 and 8% for 1999 and gradually decline to 5.5% by the year 2003 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 and gradually decline to N a t i o n a l F u e l G a s C o m p a n y 79 5.5% by the year 2002 and remain level thereafter. The annual rate of increase in the per capita cost of covered prescription drug benefits was assumed to be 8.5% for 1997, 9.0% for 1998 and 8.0% for 1999 and gradually decline to 5.5% by the year 2003 and remain level thereafter. The annual rate of increase in the per capita Medicare Part B Reimbursement was assumed to be 3.1% for 1997, 9.0% for 1998 and 8.0% for 1999 and gradually decline to 5.5% by the year 2003 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, 1999 would be increased by $38.9 million. This 1% change would also have increased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 1999 by $4.0 million. If the health care cost trend rates were decreased by 1% in each year, the Benefit Obligation as of October 1, 1999 would be decreased by $34.0 million. This 1% change would also have decreased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for 1999 by $3.4 million. N O T E H Commitments and Contingencies Environmental Matters It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remedi- ation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. Distribution Corporation and Supply Corporation have estimated their clean-up costs related to the sites described below in (i) and (ii) will be in the range of $9.4 million to $10.4 million. The minimum liability of $9.4 million has been recorded on the Consolidated Balance Sheet at September 30, 1999. Other than discussed 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 has been recovering site investigation and remediation costs in rates. Accordingly, the Consolidated Balance Sheet at September 30, 1998 included related regulatory assets of $12.4 million. Over the past several years, the Company has been negotiating settlements with its insurance carriers related to environmental investigation and remediation costs. The Company received net pro- ceeds of approximately $9.8 million in 1999 and approximately $3.5 million in 1998 related to these settlements. In addition, the Company reached a settlement with one of its insurance carriers for reim- bursement of covered costs to remediate certain sites. A portion of the net proceeds received and future proceeds accrued have been applied to reduce the Company’s environmental related regulatory assets to zero at September 30, 1999. The Company is subject to various federal, state and local laws and regulations relating to the pro- tection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory policies and pro- cedures. (i) Former Manufactured Gas Plant and Former Gasoline Plant Sites Distribution Corporation has incurred or is incurring clean-up costs at five former manufactured gas plant sites in New York and Pennsylvania. Remediation is complete at one site and substantially complete at a second site. With respect to the second site, Distribution Corporation has been desig- nated 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 N a t i o n a l F u e l G a s C o m p a n y 80 Distribution Corporation’s predecessor. At a third site, the remedial plan has been approved by the DEC and remediation is expected to begin in 2000. A fourth site is in an ongoing investigation stage with remediation being designed. The fifth is a site allegedly containing, among other things, manu- factured gas plant waste and is in the investigation stage. Supply Corporation is in the final stages of remediation of a former gasoline plant site. (ii) Third Party Waste Disposal Sites Distribution Corporation and Supply Corporation are each currently identified by the DEC or the Federal Environmental Protection Agency as one of a number of companies considered to be PRPs with respect to certain 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 Distribution Corporation or Supply Corporation with respect to the remediation of these sites will depend on such factors as the remediation plan selected, the extent of site contamination, the number of additional PRPs at each site and the portion of responsibility, if any, attributed to Distribution Corporation or Supply Corporation. Distribution Corporation is a PRP at two waste disposal sites. The remediation has been completed at one site and the remedial design selected at the second site. Supply Corporation is a PRP at one waste disposal site, which is at the investigation stage. Without being named a PRP, Distribution Corporation has also signed a consent decree (court approval pending) by which it would share the costs of remediating another waste disposal site in New York. Also without being named a PRP, Supply Corporation expects that it will participate in the cost of a site that is currently being remediated by a third party. (iii) Other Sites Distribution Corporation received, in 1998 and again in October 1999, notice that the DEC believes Distribution Corporation is responsible for contamination discovered at an additional former manufactured gas plant site in New York (without naming Distribution Corporation as a PRP). Distribution Corporation responded that other companies operated that site before Distribution Corporation’s predecessor did, that liability could be imposed upon Distribution Corporation only if hazardous substances were disposed of at the site during a period when the site was operated by Distribution Corporation’s predecessor, and that Distribution Corporation was unaware of any such disposal. Distribution Corporation 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. Distribution Corporation understands that PRPs at another third party waste disposal site have obtained records from the operator (a waste oil collector) indicating that the site received used oil from Distribution Corporation (among others). A contribution claim could, therefore, be asserted against Distribution Corporation, which has not incurred any clean-up costs at this site nor been able to reasonably estimate the probability or extent of potential liability. Supply Corporation believes that there is the possibility that it may incur costs related to certain of its measuring and regulator stations in New York. No costs have been incurred or accrued to date. Supply Corporation has estimated its exposure at approximately $0.2 million. (iv) Clean Air Standards The Company, in its international operations in the Czech Republic has substantially completed the construction of new fluidized-bed boilers at the district heating and power generation plant of PSZT in order to comply with certain clean air standards mandated by the Czech Republic govern- ment. Capital expenditures related to this reconstruction incurred by PSZT in 1999 were approxi- mately $23.0 million. N a t i o n a l F u e l G a s C o m p a n y 81 Other The Company has entered into contractual commitments in the ordinary course of business including commitments by Distribution Corporation to purchase capacity on nonaffiliated pipelines to meet cus- tomer gas supply needs. The majority of these contracts (representing 88% of current contracted demand capacity) expire within the next five years. Costs incurred under these contracts are pur- chased gas costs, subject to state commission review, and are being recovered in customer rates through inclusion in Distribution Corporation’s rate schedules. Management believes, to the extent any stranded pipeline costs are generated by the unbundling of services in Distribution Corporation’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 reg- ulatory matters arising in the normal course of business that involve rate base, cost of service and pur- chased 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 condi- tion of the Company at this time. N O T E I Business Segment Information The Company has adopted SFAS 131, “Disclosures About Segments of an Enterprise and Related Information” (SFAS 131), which changes the way the Company reports information about its business segments. SFAS 131 requires disclosure of certain financial information based upon how management evaluates the performance of its business segments. The information for 1998 and 1997 has been restated from the prior year’s presentation to conform to the 1999 presentation. 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 ser- vices, regulatory environment and geographic factors. The Utility segment operations are regulated by the NYPSC and the PaPUC and are carried out by Distribution Corporation. Distribution Corporation sells natural gas to retail customers and pro- vides natural gas transportation services in western New York and northwestern Pennsylvania. The Pipeline and Storage segment operations are regulated by the FERC and are carried out by Supply Corporation and SIP. Supply Corporation transports and stores natural gas for utilities (includ- ing 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 will be regulated by the FERC. The Exploration and Production segment, through Seneca, is engaged in exploration for, and development and purchase of, natural gas and oil reserves in the Gulf Coast of Texas and Louisiana, in California, in Wyoming and in the Appalachian region of the United States. 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 sub- sidiaries, 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 marketing of natural gas, the marketing of electricity, and the performance of energy management ser- vices for industrial, commercial, public authority and residential end-users located in the northeastern United States. N a t i o n a l F u e l G a s C o m p a n y 82 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 con- solidated 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 regulated 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 operations, extraordinary items and cumulative effects of changes in accounting (when applicable). When these items are not applicable, the Company evaluates perfor- mance based on net income. Year Ended September 30, 1999 (Thousands) Utility Pipeline and Storage Exploration and Production International Energy Marketing Total Reportable Timber Segments All Other Corporate and Intersegment Eliminations Total Consolidated 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) $ 801,053 $ 82,994 $140,212 $107,045 — 11,451 6,782 34,409 6,302 29,659 85,789 13,147 $99,088 — 234 $ 31,117 $1,261,509 $1,765 $ 98,873 91,108 — 2,208 100 — (98,873) (3,510) — $1,263,274 — 87,698 34,215 34,741 22,690 22,439 55,750 2,992 10,473 15 165 1,138 6,388 2,788 129,681 64,113 7 55 2 661 129,690 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 56,700 269,847 66 — 269,913 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) Utility Pipeline and Storage Exploration and Production International Energy Marketing Total Reportable Timber Segments All Other Corporate and Intersegment Eliminations Total Consolidated $ 867,802 3,378 44,639 $ 84,218 86,765 15,232 $113,194 11,078 21,454 $ 76,259 — 7,188 $87,187 — 31 $17,805 $1,246,465 $1,535 — 33 101,221 90,124 — 1,580 $ — $1,248,000 — 85,284 (101,221) (4,873) 33,459 21,816 50,937 7,309 Expense (Benefit) 30,076 29,644 (39,478) 2,158 91 471 5,169 118,781 1,445 24,316 97 119 2 118,880 (411) 24,024 — — 128,996 — — — 128,996 — — 128,996 Revenue from External Customers Intersegment Revenues Interest Expense Depreciation, Depletion and Amortization Income Tax Significant Noncash Item: Impairment of Oil and Gas Producing Properties Segment Profit (Loss): Income Before Cumulative Effect of Change in Accounting Expenditures for Additions 51,788 39,852 (64,110) 1,279 to Long-Lived Assets 50,680 29,145 323,627 96,987 At September 30, 1998 (Thousands) 787 320 1,904 31,500 143 661 32,304 9,893 510,652 — — 510,652 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 N a t i o n a l F u e l G a s C o m p a n y 83 Year Ended September 30, 1997 (Thousands) Utility Pipeline and Storage Exploration and Production International Energy Marketing Total Reportable Timber Segments All Other Corporate and Intersegment Eliminations Total Consolidated Revenue from External Customers Intersegment Revenues Interest Expense Depreciation, Depletion and Amortization Income Tax Expense (Benefit) Segment Profit (Loss): Net Income Expenditures for Additions to Long-Lived Assets $ 991,281 85 32,608 $ 82,883 89,811 16,068 $107,733 11,527 11,103 $ 1,910 — 1,230 $70,098 — 33 32,972 21,459 51,117 107 35,510 21,026 11,592 (954) 14 931 — 1,410 101,423 62,452 5,960 111,629 (193) 67,912 — (101,423) (5,659) 18 — $1,265,812 — 56,811 18 55 3 111,650 707 68,674 $11,536 $1,265,441 $ 371 $ 57,220 36,760 20,359 (3,348) 1,567 (609) 111,949 171 2,568 114,688 66,908 22,562 120,282 22,293 96 16,151(1) 248,292 19 — 248,311 At September 30, 1997 (Thousands) Segment Assets $1,175,885 $522,191 $469,795 $24,031 $17,083 $42,260 $2,251,245 $5,207 $10,879 $2,267,331 (1) Amount includes non-cash acquisition of $12.3 million in exchange for long-term debt obligations. GEOGRAPHIC INFORMATION: Year Ended September 30 (Thousands) Revenues from External Customers: United States Czech Republic At September 30 (Thousands) Long-Lived Assets: United States Czech Republic N O T E J Stock Acquisitions 1 9 9 9 1 9 9 8 1 9 9 7 $1,156,229 107,045 $1,263,274 $1,171,741 76,259 $1,248,000 $1,263,902 1,910 $1,265,812 $2,369,840 215,457 $2,585,297 $2,258,817 215,125 $2,473,942 $2,036,525 22,139 $2,058,664 Exploration and Production In May 1998, Seneca acquired the outstanding shares of HarCor for approximately $32.6 million. The acquisition of HarCor was accounted for in accordance with the purchase method. HarCor’s results of operations were incorporated into the Company’s consolidated financial statements for the period sub- sequent to the completion of the tender offer in May 1998. Effective August 31, 1999, HarCor was merged into Seneca. International During 1998, Horizon, through a wholly-owned subsidiary, increased its ownership interest in SCT from 36.8% at September 30, 1997 to 82.7% at September 30, 1998. The cost of acquiring these addi- tional shares was approximately $24.9 million. Also in 1998, Horizon invested in PSZT, and owned an 86.2% interest at September 30, 1998. The cost of acquiring the shares of PSZT was approximately $64.5 million. N a t i o n a l F u e l G a s C o m p a n y 84 During 1999, Horizon, through a wholly-owned subsidiary, increased its ownership interest in SCT to 82.87% for a minimal cost. SCT in turn increased its ownership in JTR, a district heating plant in the northern Bohemia region of the Czech Republic, from 34% to 65.78%. The cost of acquiring these additional shares was approximately $5.8 million. The acquisitions made in the International segment have been accounted for in accordance with the purchase method. The goodwill resulting from these acquisitions is being amortized over a twenty-year period. The goodwill is recorded in Other Assets in the Company’s Consolidated Balance Sheet. This goodwill amounted to $9.5 million and $10.1 million at September 30, 1999 and 1998, respectively. 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 cal- culated 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 out- standing for the entire fiscal year. Because of the seasonal nature of the Company’s heating business, there are substantial variations in operations reported on a quarterly basis. Quarter Ended Operating Revenues Operating Income (Loss) Income (Loss) Before Cumulative Effect Income (Loss) Per Common Share Before Cumulative Effect Diluted Basic Net Income (Loss) Available for Common Stock Earnings (Loss) Per Common Share Diluted Basic 1 9 9 9 (Thousands, except per common share amounts) 12/31/98 3/31/99 6/30/99 9/30/99 $340,422 $483,404 $248,658 $190,790 $ 56,835 $ 83,475 $ 31,319 $ 20,379 $ 37,619 $ 61,145 $ 11,840 $ 4,433 1 9 9 8 (Thousands, except per common share amounts) 12/31/97 3/31/98 6/30/98 9/30/98 $ 371,021 $462,648 $242,447 $171,884 $ 52,280 $(16,228) $ 33,726 $ 14,153 $ 37,534 $(21,262) $ 19,107 $ (3,075) $ 0.98 $ 1.58 $ 0.31 $ 0.11 $ 0.98 $(0.56) $ 0.50 $(0.08) $0.97 $1.57 $0.30 $0.11 $0.97 N/A $0.49 N/A $ 37,619(1) $ 0.98 $ 61,145 $ 1.58 $ 11,840(2) $ 0.31 $ 4,433(3) $ 0.11 $0.97 $1.57 $0.30 $0.11 $ 28,418(4) $ 0.74 $(21,262)(5) $(0.56) $ 0.50 $ 19,107 $ (3,075)(6) $(0.08) $0.73 N/A $0.49 N/A N/A - Not applicable due to antidilution. (1) Includes income of $3.9 million related to IRS audit settlement and expense of $3.5 million related to an early retirement offer. (2) Includes expense of $3.8 million related to stock appreciation rights (SAR), 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. (3) 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. (4) Includes $9.1 million negative non-cash cumulative effect of a change in accounting for depletion. (5) Includes expense of $79.1 million for impairment of oil and gas producing properties and income of $5.0 million related to IRS audit settlement. (6) Includes expense of $1.8 million for Distribution Corporation refund provision and income of $1.0 million for a net gain associated with U.S. dollar denominated debt. N O T E L Market for Common Stock and Related Shareholder Matters (unaudited) At September 30, 1999, there were 22,336 holders of National Fuel Gas Company common stock. The common stock is listed and traded on the New York Stock Exchange. Information related to restric- tions 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, 1999 and 1998, are shown below: N a t i o n a l F u e l G a s C o m p a n y 85 Quarter Ended 1 9 9 9 12/31/98 3/31/99 6/30/99 9/30/99 1 9 9 8 12/31/97 3/31/98 6/30/98 9/30/98 Price Range High Low Dividends Declared $49 5⁄8 $46 1⁄2 $50 $49 3⁄4 $48 15⁄16 $48 13⁄16 $49 1⁄8 $47 $44 7⁄8 $39 1⁄4 $37 1⁄2 $44 5⁄8 $42 11⁄16 $45 3⁄8 $39 5⁄8 $39 13⁄16 $.450 $.450 $.465 $.465 $.435 $.435 $.450 $.450 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. CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES At September 30 (Thousands) Proved Properties Unproved Properties Less - Accumulated Depreciation, Depletion and Amortization 1 9 9 9 1 9 9 8 $880,470 92,097 972,567 315,675 $656,892 $739,684 141,873 881,557 261,236 $620,321 Costs related to unproved properties are excluded from amortization as they represent unevalu- ated 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, 1999: (Thousands) Acquisition Costs Exploration Costs Total as of September 30, 1 9 9 9 Year Costs Incurred 1 9 9 9 1 9 9 8 1 9 9 7 Prior $82,994 9,103 $92,097 $12,077 9,103 $21,180 $51,226 — $51,226 $8,525 — $8,525 $11,166 — $11,166 COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES Year Ended September 30 (Thousands) Property Acquisition Costs:(1) Proved Unproved Exploration Costs Development Costs 1 9 9 9 1 9 9 8 1 9 9 7 $ 2,798 11,530 52,141 30,985 $97,454 $ 189,201 88,369 74,421 23,887 $375,878 $ 4,154 23,120 76,703 15,583 $119,560 (1) 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. N a t i o n a l F u e l G a s C o m p a n y 86 RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES Year Ended September 30 (Thousands) Operating Revenues: Natural Gas (includes revenues from sales to affiliates of $6,365, $11,065 and $10,682, respectively) Oil, Condensate and Other Liquids Total Operating Revenues(1) Production/Lifting Costs Depreciation, Depletion and Amortization ($0.89 and $0.96 per Mcfe of production, and $0.36 per dollar of operating revenues, respectively)(2) Impairment of Oil and Gas Producing Properties(3) Income Tax Expense (Benefit) Results of Operations for Producing Activities 1 9 9 9 1 9 9 8 1 9 9 7 $81,734 51,592 133,326 28,119 $89,284 31,770 121,054 23,622 $100,411 39,237 139,648 17,335 54,439 — 16,255 50,221 128,996 (28,949) 50,687 — 24,699 (excluding corporate overheads and interest charges) $34,513 $(52,836) $ 46,927 (1) Exclusive of hedging gains and losses. See further discussion in Note F - Financial Instruments. (2) In 1998, Seneca changed its method of depletion for oil and gas producing properties from the gross revenue method to the units of production method. See further discussion in Note A - Summary of Significant Accounting Policies. (3) See discussion of impairment in Note A - Summary of Significant Accounting Policies. Reserve Quantity Information (unaudited) The Company’s proved oil and gas reserves are located in the United States. The estimated quantities of proved reserves disclosed in the table below are based upon estimates by qualified Company geolo- gists and engineers and are audited by independent petroleum engineers. Such estimates are inher- ently 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. Year Ended September 30 Proved Developed and Undeveloped Reserves: Beginning of Year Extensions and Discoveries Revisions of Previous Estimates Production Sales of Minerals in Place Purchases of Minerals in Place and Other End of Year Proved Developed Reserves: Beginning of Year Gas MMcf Oil Mbbl 1 9 9 9 1 9 9 8 1 9 9 7 1 9 9 9 1 9 9 8 1 9 9 7 325,065 46,423 (13,091) (37,166) (439) 232,449 40,293 (18,623) (36,474) — 207,082 47,951 20,820 (38,586) (5,464) — 107,420 325,065 320,792 646 232,449 66,591 3,716 9,808 (4,016) (280) — 75,819 17,981 640 (4,191) (2,614) — 54,775 66,591 25,749 359 (6,224) (1,902) (1) — 17,981 230,508 194,454 163,537 48,081 11,354 14,043 End of Year 222,929 230,508 194,454 57,333 48,081 11,354 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 properties, nor an estimate of the present value of actual future cash flows to be obtained as a result of their development 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 N a t i o n a l F u e l G a s C o m p a n y 87 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 politi- cal and economic conditions of today’s world. 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) 1 9 9 9 1 9 9 8 1 9 9 7 Future Cash Inflows Less: Future Production Costs Future Development Costs Future Income Tax Expense at Applicable Statutory Rate Future Net Cash Flows Less: $2,402,308 $1,547,216 $1,072,375 560,459 185,617 477,205 1,179,027 413,753 160,884 245,120 727,459 166,989 85,216 257,172 562,998 10% Annual Discount for Estimated Timing of Cash Flows Standardized Measure of Discounted Future Net Cash Flows 471,768 $707,259 260,688 $466,771 179,798 $383,200 The principal sources of change in the standardized measure of discounted future net cash flows were as follows: Year Ended September 30 (Thousands) 1 9 9 9 1 9 9 8 1 9 9 7 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 $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 $329,244 (122,313) 78,499 1,138 (9,632) 88,228 (20,785) 43,731 (24,797) (27,317) 47,204 Future Net Cash Flows at End of Year $707,259 $466,771 $383,200 Schedule II VALUATION AND QUALIFYING ACCOUNTS (Thousands) Description Year Ended September 30, 1999 Reserve for Doubtful Accounts Year Ended September 30, 1998 Reserve for Doubtful Accounts Year Ended September 30, 1997 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 $6,232 $15,337 $ 1 $13,728 $7,842 $8,291 $15,861 $746 $18,666 $6,232 $7,672 $16,586 $ — $15,967 $8,291 (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. N a t i o n a l F u e l G a s C o m p a n y 88 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 17, 2000 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 1999. The information provided in such definitive Proxy Statement, excepting the “Report of the Compensation Committee,” and the “Corporate Performance Graph,” 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 17, 2000 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 1999. The information provided in such definitive Proxy Statement, excepting the “Report of the Compensation Committee,” and the “Corporate Performance Graph,” is incorporated herein by reference. I T E M 12 Security Ownership of Certain Beneficial Owners and 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 17, 2000 Annual Meeting of Shareholders will be filed with the SEC not later than 120 days after September 30, 1999. The information provided in such definitive Proxy Statement, excepting the “Report of the Compensation Committee,” and the “Corporate Performance Graph,” is incorporated herein by reference. I T E M 13 Certain Relationships and Related Transactions At September 30, 1999, the Company knows of no relationships or transactions required to be dis- closed pursuant to Item 404 of Regulation S-K. N a t i o n a l F u e l G a s C o m p a n y 89 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) • 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 quarterly period ended March 31, 1999 in File No. 1- 3880) 3(ii) By-Laws: 3.1 National Fuel Gas Company By-Laws as amended on September 16, 1999 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) 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) 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 (for- merly 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 Officer’s Certificate Establishing Medium-Term Notes dated October 14, 1999 (10) Material Contracts: (ii) (B) Contracts upon which Registrant’s business is substan- • • • • • • • • • tially dependent: Service Agreement No. 830016 with Texas Eastern Transmission Corporation, under Rate Schedule FT-1, dated November 2, 1995 (Exhibit 10.1, Form 10-K for fiscal year ended September 30, 1996 in File No. 1- 3880) Service Agreement No. 830017 with Texas Eastern Transmission Corporation, under Rate Schedule FT-1, dated November 2, 1995 (Exhibit 10.2, Form 10-K for fiscal year ended September 30, 1996 in File No. 1- 3880) Service Agreement with Texas Eastern Transmission Corporation, under Rate Schedule CDS, dated November 2, 1995 (Exhibit 10.3, Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880) Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation, under Rate Schedule FSS, dated April 3, 1996 [Portions of this agreement are subject to confidential treatment under Rule 24b-2] (Exhibit 10.4, Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880) Service Agreement with Engage Energy US, L.P. (for- merly St. Clair Pipelines Ltd.), dated January 29, 1996 [Portions of this agreement are subject to confidential treatment under Rule 24b-2] (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 1996 in File No. 1- 3880) Service Agreement with Empire State Pipeline under Rate Schedule FT, dated December 15, 1994 [Portions of this agreement are subject to confidential treatment under Rule 24b-2] (Exhibit 10.1, Form 10-K for fiscal year ended September 30, 1995, in File No. 1-3880) Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation under Rate Schedule ESS dated August 1, 1993 (Exhibit 10.2, Form 10-K for fiscal year ended September 30, 1995, in File No. 1-3880) Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation under Rate Schedule ESS dated September 19, 1995 (Exhibit 10.3, Form 10-K for fiscal year ended September 30, 1995, in File No. 1-3880) Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation under Rate Schedule EFT dated August 1, 1993 (Exhibit 10.4, Form 10-K for fiscal year ended September 30, 1995, in File No. 1-3880) (4) • • • • • • • • 4.1 4.2 90 N a t i o n a l F u e l G a s C o m p a n y • • • • • • • • • • (iii) • Amendment dated as of May 1, 1995 to Service Agreement between National Fuel Gas Distribution Corporation and National Fuel Gas Supply Corporation under Rate Schedule EFT dated August 1, 1993 (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 1995, in File No. 1-3880) Service Agreement with Transcontinental Gas Pipe Line Corporation under Rate Schedule FT dated August 1, 1993 (Exhibit 10.6, Form 10-K for fiscal year ended September 30, 1995, in File No. 1-3880) Service Agreement with Transcontinental Gas Pipe Line Corporation under Rate Schedule FT dated October 1, 1993 (Exhibit 10.7, Form 10-K for fiscal year ended September 30, 1995, in File No. 1-3880) Service Agreement with Columbia Gas Transmission Corporation under Rate Schedule FTS, dated November 1, 1993 and executed February 13, 1994 (Exhibit 10.1, Form 10-K for fiscal year ended September 30, 1994 in File No. 1-3880) Service Agreement with Columbia Gas Transmission Corporation under Rate Schedule FSS, dated November 1, 1993 and executed February 13, 1994 (Exhibit 10.2, Form 10-K for fiscal year ended September 30, 1994 in File No. 1-3880) Service Agreement with Columbia Gas Transmission Corporation under Rate Schedule SST, dated November 1, 1993 and executed February 13, 1994 (Exhibit 10.3, Form 10-K for fiscal year ended September 30, 1994 in File No. 1-3880) Gas Transportation Agreement with Tennessee Gas Pipeline Company under Rate Schedule FT-A (Zone 4), dated September 1, 1993 (Exhibit 10.1, Form 10-K for fiscal year ended September 30, 1993 in File No. 1- 3880) Gas Transportation Agreement with Tennessee Gas Pipeline Company under Rate Schedule FT-A (Zone 5), dated September 1, 1993 (Exhibit 10.2, Form 10-K for fiscal year ended September 30, 1993 in File No. 1- 3880) Service Agreement with CNG Transmission Corporation under Rate Schedule FT, dated October 1, 1993 (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 1993 in File No. 1-3880) Service Agreement with CNG Transmission Corporation under Rate Schedule GSS, dated October 1, 1993 (Exhibit 10.6, Form 10-K for fiscal year ended September 30, 1993 in File No. 1-3880) 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) 10.1 Tenth Amendment to Employment Agreement with • • • • Bernard J. Kennedy, effective September 1, 1999 Agreement, dated August 1, 1989, with Richard Hare (Exhibit 10-Q, Form 10-K for fiscal year ended September 30, 1989 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) • • • • • • • • • • Form of Employment Continuation and Noncompetition Agreement, dated as of December 11, 1998, with Bruce H. Hale and Richard Hare (Exhibit 10.2, Form 10-Q for the quarterly period ended June 30, 1999 in File No. 1-3880) 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) National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.9, Form 10-K for fiscal year ended September 30, 1996 in File No. 1-3880) 10.2 Amended and Restated National Fuel Gas Company • • • • • • 1997 Award and Option Plan, dated December 9, 1999 (being submitted to Shareholder vote at the Annual Meeting in February 2000) 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) N a t i o n a l F u e l G a s C o m p a n y 91 • • • • • • • 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 quar- terly 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) 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) 10.4 10.3 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 Second Amended and Restated Split Dollar Insurance Agreement dated August 9, 1999 with Richard Hare 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) • 10.5 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 Second Amended and Restated Split Dollar Insurance Agreement dated June 15, 1999 with Gerald T. Wehrlin 10.6 10.7 Amended and Restated Split Dollar Insurance and Death Benefit Agreement dated September 15, 1997 with Walter E. DeForest 10.8 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 10.9 Amended and Restated Split Dollar Insurance and Death Benefit Agreement dated September 15, 1997 with Dennis J. Seeley 10.10 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 10.11 Split Dollar Insurance and Death Benefit Agreement dated September 15, 1997 with Bruce H. Hale 10.12 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 10.13 Split Dollar Insurance and Death Benefit Agreement dated September 15, 1997 with David F. Smith N a t i o n a l F u e l G a s C o m p a n y 92 10.14 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 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) 10.15 Amendments to National Fuel Gas Company and • • • Participating Subsidiaries Executive Retirement Plan effective September 16, 1999 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 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 (13) Business segment discussion as contained in the 1999 Annual Report and incorporated by reference into this Form 10-K Subsidiaries of the Registrant: See Item 1 of Part I of this Annual Report on Form 10-K (21) • (23) Consents of Experts: 23.1 Consent of Ralph E. Davis Associates, Inc. 23.2 Consent of Independent Accountants (27) Financial Data Schedules: 27.1 Financial Data Schedule for the Twelve Months Ended September 30, 1999 27.2 Restated Financial Data Schedule for the Twelve Months Ended September 30, 1998 (99) Additional Exhibits: 99.1 Report of Ralph E. Davis Associates, Inc. All other exhibits are omitted because they are not applicable or the required information is shown else- where in this Annual Report on Form 10-K. •Incorporated herein by reference as indicated. S I G N AT U R E S 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 9, 1999 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. S I G N AT U R E / T I T L E S I G N AT U R E / T I T L E /s/ B. J. Kennedy B. J. Kennedy Chairman of the Board, Chief Executive Officer and Director Date: December 9, 1999 /s/ P. C. Ackerman P. C. Ackerman President, Principal Financial Officer and Director Date: December 9, 1999 /s/ R. T. Brady R. T. Brady Director Date: December 9, 1999 /s/ J. V. Glynn J. V. Glynn Director Date: December 9, 1999 /s/ W. J. Hill W. J. Hill Director Date: December 9, 1999 /s/ B. S. Lee B. S. Lee Director Date: December 9, 1999 /s/ E. T. Mann E. T. Mann Director Date: December 9, 1999 /s/ G. L. Mazanec G. L. Mazanec Director Date: December 9, 1999 /s/ G. H. Schofield G. H. Schofield Director Date: December 9, 1999 /s/ J. P. Pawlowski J. P. Pawlowski Treasurer and Principal Accounting Officer Date: December 9, 1999 N a t i o n a l F u e l G a s C o m p a n y 93 Officers of Principal Subsidiaries O F F I C E R S NATIONAL FUEL GAS COMPANY 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 Bernard J. Kennedy Chairman of the Board David F. Smith President Walter E. DeForest Senior Vice President Joseph P. Pawlowski Senior Vice President and Treasurer Dennis J. Seeley Senior Vice President Gerald T. Wehrlin Senior Vice President Carl M. Carlotti Vice President Anna Marie Cellino Vice President and Secretary NATIONAL FUEL GAS SUPPLY CORPORATION Bernard J. Kennedy Chairman of the Board Richard Hare President Philip C. Ackerman Executive Vice President Bruce H. Hale Senior Vice President John R. Pustulka Vice President SENECA RESOURCES CORPORATION Bernard J. Kennedy Chairman of the Board James A. Beck President Gerald T. Wehrlin Controller William M. Petmecky Senior Vice President and Secretary Don A. Brown Vice President Gil E. Klefstad Vice President John F. McKnight Vice President Barry L. McMahan Vice President NATIONAL FUEL RESOURCES, INC. Robert J. Kreppel President William M. Petmecky Secretary and Treasurer James D. Ramsdell Vice President Ronald J. Tanski Vice President and Controller Roger W. Wilcox Vice President Robert J. Wright Vice President William A. Ross Vice President Joseph P. Pawlowski Secretary and Treasurer Emmett E. Wassell Vice President Calvin H. Friedrich Treasurer HIGHLAND LAND & MINERALS, 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 N a t i o n a l F u e l G a s C o m p a n y 94 D I R E C T O R S 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 American Precision Industries, Inc., 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 Falls, 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* President of the Institute of Gas Technology, a not-for- profit research and educational institution, 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. George H. Schofield** Retired Chairman of the Board of Directors and Chief Executive Officer of Zurn Industries, Inc., a provider of products and services for water quality control systems, Erie, Pennsylvania. Board member since 1990. Director of The Goodyear Tire & Rubber Company. * Member of Audit Committee ** Chairman, Audit Committee † Member of Compensation Committee † † Chairman, Compensation Committee ∆ Member of Executive Committee ∆ ∆ Chairman, Executive Committee N a t i o n a l F u e l G a s C o m p a n y 95 G L O S S A RY 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. 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. Combined Cycle The combination of one or more gas turbines and steam turbines in an electric generation plant. This technology allows electricity to be produced from otherwise lost waste heat exiting from one or more gas turbines. This heat is utilized by a steam turbine to produce additional electricity. Degree Day A measure of the coldness of the weather experienced, based on the extent to which the daily average temperature falls below a reference temperature, usually 65 degrees Fahrenheit. 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. 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. Interruptible Transportation and/or Storage The trans- portation and/or storage service that, in accordance with contractual arrangements, can be interrupted by the sup- plier of such service. Mbbl Thousand barrels Mcf Thousand cubic feet 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. MMcf Million cubic feet MMcfe Million cubic feet equivalent (1 barrel of oil = 6 Mcf of 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 Pay Sands The geological deposit in which oil and/or gas is found in commercial quantities. Reserves Estimated volumes of oil, gas or other miner- als that can be recovered from deposits in the earth with reasonable certainty. 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 con- tracts that, because of restructuring, may not be directly recoverable from customers. 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 with- drawal during periods of high market demand. 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 tempera- tures 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. N a t i o n a l F u e l G a s C o m p a n y 96 I N V E S T O R I N F O R M AT I O N Common Stock Transfer Agent and Registrar* Annual Meeting ChaseMellon Shareholder Services, L.L.C. 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. The Annual Meeting of Shareholders will be held at 10 a.m. (local time) on Thursday, February 17, 2000, at The Ritz-Carlton, Palm Beach, 100 South Ocean Boulevard, Manalapan, Florida 33462. Formal notice of the meeting, proxy statement and proxy will be mailed to shareholders of record as of December 20, 1999. Stock Listing Investor Relations 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 ChaseMellon Shareholder Services, L.L.C., the agent for the Plan, at: ChaseMellon Shareholder Services, L.L.C. 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 Marine Midland Center Buffalo, N.Y. 14203 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. 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 1999 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 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 release section and subscribe. 97 Printed on Recyclable Paper with Soybean Inks National Fuel Gas Company 10 Lafayette Square Buffalo, NY 14203 (716) 857-7000 www.nationalfuelgas.com