1 - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 --------------------- FORM 10-K --------------------- [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 COMMISSION FILE NUMBER: 1-9743 ENRON OIL & GAS COMPANY (Exact name of registrant as specified in its charter) <TABLE> <S> <C> DELAWARE 47-0684736 (State or other jurisdiction (I.R.S. Employer of incorporation or organization) Identification No.) </TABLE> 1400 SMITH STREET, HOUSTON, TEXAS 77002-7369 (Address of principal executive offices) (zip code) REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 713-853-6161 --------------------- SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT: <TABLE> <S> <C> TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED - --------------------------------------------- --------------------------------------------- Common Stock, $.01 par value New York Stock Exchange </TABLE> 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 (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]. Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]. Aggregate market value of the voting stock held by nonaffiliates of the registrant, based on the closing sale price in the daily composite list for transactions on the New York Stock Exchange on February 26, 1999 was $1,108,372,096. As of March 1, 1999, there were 153,731,704 shares of the registrant's Common Stock, $.01 par value, outstanding. DOCUMENTS INCORPORATED BY REFERENCE. Certain portions of the registrant's definitive Proxy Statement to be filed by April 30, 1999 ("Proxy Statement") are incorporated in Part III by reference. - -------------------------------------------------------------------------------- - --------------------------------------------------------------------------------
2 TABLE OF CONTENTS PART I <TABLE> <CAPTION> PAGE ---- <S> <C> <C> <C> Item 1. Business General..................................................... 1 Business Segments........................................... 2 Exploration and Production.................................. 2 Wellhead Volumes and Prices, and Lease and Well Expenses.... 7 Competition................................................. 8 Regulation.................................................. 8 Relationship Between the Company and Enron Corp............. 10 Other Matters............................................... 13 Current Executive Officers of the Registrant................ 16 Item 2. Properties Oil and Gas Exploration and Production Properties and Reserves.................................................... 17 Item 3. Legal Proceedings........................................... 20 Item 4. Submission of Matters to a Vote of Security Holders......... 20 PART II Item 5. Market for the Registrant's Common Equity and Related Shareholder Matters......................................... 21 Item 6. Selected Financial Data..................................... 22 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................................. 23 Item 7A. Quantitative and Qualitative Disclosures About Market Risk........................................................ 34 Item 8. Financial Statements and Supplementary Data................. 34 Item 9. Disagreements on Accounting and Financial Disclosure........ 34 PART III Item 10. Directors and Executive Officers of the Registrant.......... 34 Item 11. Executive Compensation...................................... 35 Item 12. Security Ownership of Certain Beneficial Owners and Management.................................................. 35 Item 13. Certain Relationships and Related Transactions.............. 35 PART IV Item 14. Financial Statements and Financial Statement Schedule, Exhibits and Reports on Form 8-K............................ 35 </TABLE> i
3 PART I ITEM 1. BUSINESS GENERAL Enron Oil & Gas Company (the "Company"), a Delaware corporation organized in 1985, is engaged, either directly or through a marketing subsidiary with regard to domestic operations or through various subsidiaries with regard to international operations, in the exploration for, and the development, production and marketing of, natural gas and crude oil primarily in major producing basins in the United States, as well as in Canada, Trinidad and India and, to a lesser extent, selected other international areas. The Company's principal producing areas are further described under "Exploration and Production" below. At December 31, 1998, the Company's estimated net proved natural gas reserves were 5,229 billion cubic feet ("Bcf"), including 1,180 Bcf of proved undeveloped methane reserves in the Big Piney deep Paleozoic formations, and estimated net proved crude oil, condensate and natural gas liquids reserves were 105 million barrels ("MMBbl"). (See "Supplemental Information to Consolidated Financial Statements"). At such date, approximately 53% of the Company's reserves (on a natural gas equivalent basis) was located in the United States, 9% in Canada, 18% in Trinidad, 18% in India and 2% in China. As of December 31, 1998, the Company employed approximately 1,190 persons, including foreign national employees. The Company's business strategy is to maximize the rate of return on investment of capital by controlling both operating and capital costs and enhancing the certainty of future revenues through the selective use of various marketing mechanisms. This strategy enhances the generation of both income and cash flow from each unit of production and allows for the growth of production on a cost-effective basis by optimizing the reinvestment of cash flow. The Company continued to focus its 1998 drilling activity toward natural gas deliverability in addition to natural gas reserve enhancement and to a lesser extent crude oil exploitation. The Company also continues to focus on the cost-effective utilization of advances in technology associated with gathering, processing and interpretation of 3-D seismic data, developing reservoir simulation models and drilling operations through the use of new and/or improved drill bits, mud motors, mud additives, formation logging techniques and reservoir fracturing methods. These advanced technologies are used, as appropriate, throughout the Company to reduce the risks associated with all aspects of oil and gas reserve exploration, exploitation and development. The Company implements its strategy by emphasizing the drilling of internally generated prospects in order to find and develop low cost reserves. Achieving and maintaining the lowest possible operating cost structure are also important goals in the implementation of the Company's strategy. Consistent with the Company's desire to optimize the use of its assets, it also maintains a strategy of selling selected oil and gas properties that for various reasons may no longer fit into future operating plans, or which are not assessed to have sufficient future growth potential and when the economic value to be obtained by selling the properties and reserves in the ground is evaluated to be greater than what would be obtained by holding the properties and producing the reserves over time. As a result, the Company typically receives each year a varying but substantial level of proceeds related to such sales which proceeds are available for general corporate use. As of December 31, 1998, Enron Corp. owned 54% of the outstanding shares of the common stock of the Company. (See "Relationship Between the Company and Enron Corp."). In December 1998, Enron Corp. publicly disclosed that it had received an unsolicited indication of interest from a third party with respect to exploring a possible transaction pursuant to which the third party would acquire Enron Corp.'s shares of common stock of the Company, and offer to acquire the remaining shares of outstanding common stock of the Company. In response to this indication of interest, the Board of Directors of the Company has established a special committee consisting of two independent directors who have retained a financial advisor and legal counsel. Although Enron Corp. has publicly indicated that it currently intends to actively explore alternative transactions for its Company common stock along with the unsolicited indication of interest, there can be no assurance that any such transactions will be pursued or, if pursued, will be consummated. Unless the context otherwise requires, all references herein to the Company include Enron Oil & Gas Company, its predecessors and subsidiaries, and any reference to the ownership of interests or pursuit of 1
4 operations in any international areas by the Company recognizes that all such interests are owned and operations are pursued by subsidiaries of Enron Oil & Gas Company. Unless the context otherwise requires, all references herein to Enron Corp. include Enron Corp., its predecessors and affiliates, other than the Company and its predecessors and subsidiaries. With respect to information on the Company's working interest in wells or acreage, "net" oil and gas wells or acreage are determined by multiplying "gross" oil and gas wells or acreage by the Company's working interest in the wells or acreage. Unless otherwise defined, all references to wells are gross. BUSINESS SEGMENTS The Company's operations are all natural gas and crude oil exploration and production related. EXPLORATION AND PRODUCTION NORTH AMERICA OPERATIONS United States. The Company's eight principal United States producing areas are the Big Piney area of Wyoming, South Texas area, East Texas area, Offshore Gulf of Mexico area, Canyon/Strawn Trend area of West Texas, Sand Tank and Pitchfork Ranch areas of New Mexico and Vernal area of Utah. Properties in these areas comprised approximately 81% of the Company's United States reserves (on a natural gas equivalent basis) and 82% of the Company's United States net natural gas deliverability as of December 31, 1998 and are substantially all operated by the Company. The Company's other United States natural gas and crude oil producing properties are located primarily in other areas of Texas, Utah, New Mexico, Oklahoma, California, Mississippi and Kansas. At December 31, 1998, 93% of the Company's proved United States reserves, including the reserves in the Big Piney deep Paleozoic formations (on a natural gas equivalent basis), was natural gas and 7% was crude oil, condensate and natural gas liquids. A substantial portion of the Company's United States natural gas reserves is in long-lived fields with well-established production histories. The Company believes that opportunities exist to increase production in many of these fields through continued infill and other development drilling. Big Piney Area. The Company's largest reserve accumulation is located in the Big Piney area in Sublette and Lincoln counties in southwestern Wyoming. The Company is the holder of the largest productive acreage base in this area, with approximately 280,000 net acres under lease directly within field limits. The Company operates approximately 800 natural gas and crude oil wells in this area in which it owns an 85% average working interest. Deliveries from the area net to the Company averaged 118 million cubic feet ("MMcf") per day of natural gas and 4.0 thousand barrels ("MBbl") per day of crude oil, condensate, and natural gas liquids in 1998. At December 31, 1998, natural gas deliverability net to the Company was approximately 110 MMcf per day. The current principal producing intervals are the Almy, Mesaverde and Frontier formations. The Frontier formation, which occurs at 6,500 to 10,000 feet, contains approximately 64% of the Company's Big Piney proved developed reserves. The Company drilled 44 wells in the Big Piney area in 1998 and anticipates an active drilling program will continue for several years. The Company has recorded as proved undeveloped reserves 1,180 Bcf of methane contained, along with high concentrations of carbon dioxide as well as small amounts of other gaseous substances, in the deep Wyoming Paleozoic (Madison) formation located under acreage leased by the Company and held by production in the Big Piney area. In January 1999, the Company acquired certain adjacent Madison formation producing interests that include the rights to an agreement covering the processing of natural gas from such adjacent interests from the Madison formation through an existing plant operated by another company in the industry. 2
5 South Texas Area. The Company's activities in South Texas are focused in the Lobo, Wilcox and Frio producing horizons. The principal areas of activity are in the Lobo and Wilcox Trends which occur primarily in Webb, Zapata and Duval counties, as well as the Frio Trend in Matagorda County. In Matagorda County, two wells were completed in 1998, each with a rate of 40 MMcf per day of natural gas and 2.0 MBbl per day of condensate. The Company operates approximately 420 wells in the South Texas area, and production is primarily from the Frio, Wilcox and Lobo sands at depths ranging from 5,000 to 16,000 feet. The Company has approximately 273,000 net leasehold acres and more than 40,000 net mineral fee acres in this area. Natural gas deliveries net to the Company averaged approximately 162 MMcf per day in 1998. At December 31, 1998, natural gas deliverability from this area net to the Company was approximately 182 MMcf per day. The Company drilled 47 wells in the South Texas area in 1998, acquired 758 square miles of new 3-D seismic and leased 64,500 net acres. An active drilling program in this area is anticipated to continue for several years. East Texas Area. The Company's activities in the East Texas area are primarily in the Carthage field, located in Panola County, the North Milton field, located in northern Harris County and the Stowell/Big Hill area, located in Jefferson and Chambers Counties. The Carthage field production is primarily from the Cotton Valley, Travis Peak and Pettit formations. The Company holds approximately 17,900 net acres under lease with an average 74% working interest in this area. The Company drilled 29 wells in the Carthage field in 1998 and anticipates an active drilling program will continue for several years. The Company has continued its activity in the North Milton field where it now operates 27 wells and holds a 100% working interest in the acreage. The Company expects to drill additional wells during 1999. The Company drilled 10 wells in the Stowell/Big Hill area in 1998 and expects to continue expansion of the program in 1999. Net deliveries from the East Texas area averaged 56.4 MMcf per day of natural gas and 2.3 MBbl per day of crude oil, condensate and natural gas liquids in 1998. At December 31, 1998, deliverability from the area was approximately 80 MMcf per day of natural gas with 2.0 MBbl per day of crude oil, condensate and natural gas liquids both net to the Company. Offshore Gulf of Mexico Area. During 1998, the Company participated in two lease sales offering leases in the Gulf of Mexico and acquired approximately 20,700 net acres (6 leases). As a result of the lease sale activity, the Company acquired two deepwater (greater than 600 feet) tracts to add to the 19 deepwater tracts held at the end of 1997. During 1998, the Company made a significant acquisition in the OCS Gulf of Mexico purchasing a 19% working interest in the Matagorda Island 623 field which increased the Company's natural gas deliveries, adding 55 MMcf per day net to the Company. Development of the Eugene Island 135 discovery continued with a third development well increasing the Company's net field production to 17 MMcf per day and 760 barrels of condensate per day. At December 31, 1998, the Company held an interest in 184 blocks in the Offshore Gulf of Mexico area totaling approximately 544,000 net acres. Of these 184 blocks, located predominantly in federal waters offshore Texas and Louisiana, 127 are operated by the Company. Natural gas deliveries from this area averaged 116 MMcf per day during 1998 net to the Company with total deliveries at year end of 152 MMcf per day. A substantial portion of such deliveries was from interests in the Matagorda Island and Mustang Island areas of offshore Texas with significant volumes also coming from Eugene Island 135. Deliverability from the offshore Gulf of Mexico area at December 31, 1998 was approximately 161 MMcf per day net to the Company sourced principally as noted above. During 1998, the Company participated in the drilling of 10 wells (3.9 net wells) in the Gulf of Mexico. In 1999, the Company anticipates participating in the drilling of 5-10 wells. Canyon/Strawn Trend Area. The Company's activities in this area have been concentrated in Crockett, Terrell and Val Verde Counties in Texas where the Company drilled 21 natural gas wells during 1998. The Company holds approximately 66,000 net acres and now operates approximately 350 natural gas wells in this area in which it owns a 90% average working interest. Production is from the Canyon sands and Strawn limestone at depths from 5,500 to 12,500 feet. At December 31, 1998, natural gas deliverability net to the Company was approximately 35 MMcf per day. The Company plans an aggressive program on several new prospects in 1999. 3
6 Sand Tank Area. The Sand Tank area located in Eddy County, New Mexico produces from the Chester, Morrow, and Atoka formations. Natural gas deliveries for 1998 averaged 16 MMcf per day and deliveries of crude oil, condensate and natural gas liquids averaged .3 MBbl per day in 1998 both net to the Company. At year end 1998, deliverability, net to the Company, was approximately 15 MMcf per day of natural gas and .2 MBbl per day of crude oil, condensate and natural gas liquids. The Company holds 14,000 net acres and has an average working interest of approximately 60%. Several wells are planned in 1999 for this stacked-pay area. Pitchfork Ranch Area. The Pitchfork Ranch area located in Lea County, New Mexico, produces primarily from the Bone Spring, Wolfcamp, Atoka and Morrow formations. In 1998, deliveries net to the Company averaged 18 MMcf per day of natural gas and approximately 2.0 MBbl per day of crude oil, condensate and natural gas liquids. At December 31, 1998, deliverability net to the Company was approximately 21 MMcf per day of natural gas and 1.8 MBbl per day of crude oil, condensate and natural gas liquids. The Company holds approximately 34,000 net acres and is continuing to interpret a 3-D seismic survey shot over this entire area. The Company expects to maintain a drilling program in this area in 1999. Vernal Area. In the Vernal area, located primarily in Uintah County, Utah, the Company operates approximately 305 producing wells and presently controls approximately 77,000 net acres. In 1998, natural gas deliveries net to the Company from the Vernal area averaged 21 MMcf per day. Deliverability at December 31, 1998, was approximately 26 MMcf per day. Production is from the Green River and Wasatch formations located at depths between 4,500 and 8,000 feet. The Company has an average working interest of approximately 60%. Numerous drilling opportunities will be available in this area in 1999. Canada. The Company is engaged in the exploration for and the development, production and marketing of natural gas, natural gas liquids and crude oil in Western Canada, principally in the provinces of Alberta, Saskatchewan, and Manitoba. The Company conducts operations from offices in Calgary, Alberta, and produces natural gas and crude oil from five major areas. The Sandhills area in southwestern Saskatchewan is the largest single natural gas producing area in Canada for the Company. In 1998, 150 wells were drilled in the area and additional acreage and wells were acquired in the area resulting in deliverability of approximately 44 MMcf per day net to the Company at December 31, 1998. The Blackfoot area in southeastern Alberta is the second largest natural gas producing area in Canada for the Company. In 1998, 16 new wells were drilled and numerous recompletions, workovers and facility optimizations were carried out resulting in deliverability of approximately 30 MMcf per day and 1.2 MBbl per day of crude oil and condensate net to the Company at December 31, 1998. Total Canadian natural gas deliverability net to the Company at December 31, 1998 was approximately 120 MMcf per day, and the Company held approximately 555,000 net undeveloped acres in Canada. Total Canadian natural gas deliveries net to the Company for 1998 averaged approximately 105 MMcf per day. The Company expects to maintain an active drilling program in Western Canada for several years. OUTSIDE NORTH AMERICA OPERATIONS The Company has producing operations offshore Trinidad and India, and is evaluating and conducting exploration, exploitation and development in selected other international areas. Trinidad. In November 1992, the Company was awarded a 95% working interest concession in the South East Coast Consortium ("SECC") Block offshore Trinidad, encompassing three undeveloped fields, previously held by three government-owned energy companies. The Kiskadee field has since been developed. The Ibis field is under development and the Oilbird field is anticipated to be developed over the next several years. Existing surplus processing and transportation capacity at the Pelican field facilities owned and operated by Trinidad and Tobago government-owned companies is being used to process and transport the production. Natural gas is being sold into the local market under a take-or-pay agreement with the National Gas Company of Trinidad and Tobago. In 1998, deliveries net to the Company averaged 139 MMcf per day of natural gas, which includes 24 MMcf per day of gas balancing volumes relating to a field allocation agreement, and 3.0 MBbl per day of crude oil and condensate. At December 31, 1998, the Company held approximately 144,000 net undeveloped acres in Trinidad. 4
7 In 1995, the Company was awarded the right to develop the modified U(a) block near the SECC Block. A production sharing contract was signed with the Government of Trinidad and Tobago in 1996. The contract committed the Company to the acquisition of 3-D seismic data and the drilling of three wells. The first well was drilled in 1998 and was successful, encountering over 400 feet of net pay, resulting in the largest exploration discovery in the Company's history. The Company estimates the gross proved reserves of the discovery to be over 600 billion cubic feet equivalent. India. In December 1994, the Company signed agreements covering profit sharing, joint operations and product sales and representing a 30% working interest in, and was designated operator of, the Tapti, Panna and Mukta Blocks located offshore Bombay, India. The blocks were previously operated by the Indian national oil company, Oil & Natural Gas Corporation Limited, which retained a 40% working interest. The 363,000 acre Tapti Block contains two major proved natural gas accumulations delineated by 22 expendable exploration wells that have been plugged. The Company has substantially implemented an initial development plan for the Tapti Block accumulations and production began during 1997. At December 31, 1998, production, net to the Company, from Tapti was 50 MMcf per day. The 106,000 acre Panna Block and the 192,000 acre Mukta Block are partially developed with 65 wells capable of producing from six production platforms located in the Panna and Mukta fields. The Panna field was producing approximately 7.1 MBbl per day of crude oil net to the Company as of December 31, 1998. Natural gas sales began from the Panna field during the first quarter of 1998 and as of December 31, 1998, production, net to the Company, was 18 MMcf per day. The Company intends to continue development of the fields. Venezuela. The Company was awarded exploration, exploitation and development rights for a block offshore the eastern state of Sucre, Venezuela in early 1996. The Company signed agreements with the government of Venezuela and other participants associated with a concession awarded in the Gulf of Paria East. The Company holds an initial 90% working interest in the joint venture and acts as operator. One exploratory well was drilled during 1998 and encountered hydrocarbons. Additional evaluation work is being done, and another well is expected to be drilled during 1999. China. In August 1997, the Company signed a 30-year production sharing contract with the China National Petroleum Corporation for the appraisal and potential development of crude oil and natural gas reserves within the Chuanzhong Block situated in one of China's oldest producing areas in the central Sichuan Province. The Company holds a 100% working interest in the fields and is the operator. The contract provides for a two-year evaluation period during which the Company will perform three workover/stimulations to improve productivity in existing wells and will drill three new wells in the proved areas. Further commitments, if any, would arise from entering into the development period as specified in the contract. In 1998, the Company drilled and completed one well and recompleted another well. Other International. The Company continues to evaluate other selected conventional natural gas and crude oil opportunities outside North America by pursuing other exploitation opportunities in countries where indigenous natural gas and crude oil reserves have been identified, particularly where synergies in natural gas transportation, processing and power generation can be optimized with other Enron Corp. affiliated companies. The Company is also participating in discussions concerning the potential for natural gas development opportunities in Mozambique as well as other opportunities in Trinidad, India and other countries. (See "Relationship Between the Company and Enron Corp. - Business Opportunity Agreement" for a further discussion of the relationship between the Company and Enron Corp. in the Mozambique project.) 5
8 MARKETING Wellhead Marketing. The Company's North America wellhead natural gas production is currently being sold on the spot market and under long-term natural gas contracts at market responsive prices. In many instances, the long-term contract prices closely approximate the prices received for natural gas being sold on the spot market. Wellhead natural gas volumes from Trinidad are sold at prices that are based on a fixed price schedule with annual escalations. Under terms of the production sharing contracts, natural gas volumes in India are sold to a nominee of the Government of India at a price linked to a basket of world market fuel oil quotations with floor and ceiling limits. Approximately 7% of the Company's wellhead natural gas production is currently being sold to pipeline and marketing subsidiaries of Enron Corp. The Company believes that the terms of its transactions and agreements with Enron Corp. are and intends that future such transactions and agreements will be at least as favorable to the Company as could be obtained from third parties. Substantially all of the Company's wellhead crude oil and condensate is sold under various terms and arrangements at market responsive prices. Approximately 1% of the Company's wellhead crude oil and condensate production is currently being sold to subsidiaries of Enron Corp. Other Marketing. Enron Oil & Gas Marketing, Inc. ("EOGM"), a wholly-owned subsidiary of the Company, is a marketing company engaging in various marketing activities. Both the Company and EOGM contract to provide, under short and long-term agreements, natural gas to various purchasers and then aggregate the necessary supplies for the sales with purchases from various sources including third-party producers, marketing companies, pipelines or from the Company's own production and arrange for any necessary transportation to the points of delivery. In addition, EOGM has purchased and constructed several small gathering systems in order to facilitate its entry into the gathering business on a limited basis. Both the Company and EOGM utilize other short and long-term hedging and trading mechanisms including sales and purchases utilizing NYMEX-related commodity market transactions. These marketing activities have provided an effective balance in managing a portion of the Company's exposure to commodity price risks for both natural gas and crude oil and condensate wellhead prices. (See "Other Matters - Risk Management"). In September 1992, the Company sold a volumetric production payment for $326.8 million to a limited partnership. Delivery obligations were terminated in December 1998. (See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Sale of Volumetric Production Payment"). In March 1995, in a series of transactions with Enron Corp., the Company exchanged all of its fuel supply and purchase contracts and related price swap agreements associated with a Texas City cogeneration plant (the "Cogen Contracts") for certain natural gas price swap agreements (the "Swap Agreements") of equivalent value. As a result of the transactions, the Company was relieved of all performance obligations associated with the Cogen Contracts. The Company will realize net operating revenues and receive corresponding cash payments of approximately $91 million during the period extending through December 31, 1999, under the terms of the Swap Agreements. The estimated fair value of the Swap Agreements was approximately $81 million at the date the Swap Agreements were received. The net effect of this series of transactions has resulted in increases in net operating revenues and cash receipts for the Company during 1995 and 1996 of approximately $13 million and $7 million, respectively, with offsetting decreases in 1998 and 1999 versus that anticipated under the Cogen Contracts. 6
9 WELLHEAD VOLUMES AND PRICES, AND LEASE AND WELL EXPENSES The following table sets forth certain information regarding the Company's wellhead volumes of and average prices for natural gas per thousand cubic feet ("Mcf"), crude oil and condensate, and natural gas liquids per barrel ("Bbl"), and average lease and well expenses per thousand cubic feet equivalent ("Mcfe" - natural gas equivalents are determined using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of crude oil, condensate or natural gas liquids) delivered during each of the three years in the period ended December 31, 1998: <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, ------------------------ 1998 1997 1996 ------ ------ ------ <S> <C> <C> <C> VOLUMES (PER DAY) Natural Gas (MMcf) United States(1)....................................... 671 657 608 Canada................................................. 105 101 98 Trinidad............................................... 139 113 124 India.................................................. 56 18 - ------ ------ ------ Total............................................. 971 889 830 ====== ====== ====== Crude Oil and Condensate (MBbl) United States.......................................... 14.0 11.7 9.2 Canada................................................. 2.6 2.5 2.4 Trinidad............................................... 3.0 3.4 5.2 India.................................................. 5.1 2.3 2.8 ------ ------ ------ Total............................................. 24.7 19.9 19.6 ====== ====== ====== Natural Gas Liquids (MBbl) United States.......................................... 2.9 2.6 1.3 Canada................................................. 1.0 1.3 1.2 ------ ------ ------ Total............................................. 3.9 3.9 2.5 ====== ====== ====== AVERAGE PRICES Natural Gas ($/Mcf) United States(2)....................................... $ 1.93 $ 2.32 $ 2.04 Canada................................................. 1.40 1.43 1.15 Trinidad............................................... 1.06 1.05 1.00 India.................................................. 2.41 2.79 - Composite......................................... 1.78 2.07 1.78 Crude Oil and Condensate ($/Bbl) United States.......................................... $12.84 $19.81 $21.88 Canada................................................. 11.82 17.16 18.01 Trinidad............................................... 12.26 18.68 19.76 India.................................................. 12.86 20.05 20.17 Composite......................................... 12.66 19.30 20.60 Natural Gas Liquids ($/Bbl) United States.......................................... $ 8.38 $12.76 $14.67 Canada................................................. 5.32 8.94 9.14 Composite......................................... 7.56 11.54 11.99 LEASE AND WELL EXPENSES ($/MCFE) United States.......................................... $ .22 $ .23 $ .19 Canada................................................. .37 .39 .34 Trinidad............................................... .12 .16 .16 India.................................................. .24 .64 .99 Composite......................................... .24 .26 .22 </TABLE> - --------------- (1) Includes 48 MMcf per day in 1998, 1997 and 1996 delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended. Delivery obligations were terminated in December 1998. (2) Includes an average equivalent wellhead value of $1.53 per Mcf in 1998, $1.73 per Mcf in 1997, and $1.17 per Mcf in 1996 for the volumes described in note (1), net of transportation costs. 7
10 COMPETITION The Company actively competes for reserve acquisitions and exploration/exploitation leases, licenses and concessions, frequently against companies with substantially larger financial and other resources. To the extent the Company's exploration budget is lower than that of certain of its competitors, the Company may be disadvantaged in effectively competing for certain reserves, leases, licenses and concessions. Competitive factors include price, contract terms, and quality of service, including pipeline connection times and distribution efficiencies. In addition, the Company faces competition from other producers and suppliers, including competition from other world wide energy supplies, such as natural gas from Canada. REGULATION United States Regulation of Natural Gas and Crude Oil Production. Natural gas and crude oil production operations are subject to various types of regulation, including regulation in the United States by state and federal agencies. United States legislation affecting the oil and gas industry is under constant review for amendment or expansion. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations which, among other things, require permits for the drilling of wells, regulate the spacing of wells, prevent the waste of natural gas and liquid hydrocarbon resources through proration and restrictions on flaring, require drilling bonds and regulate environmental and safety matters. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its profitability. A substantial portion of the Company's oil and gas leases in the Big Piney area and in the Gulf of Mexico, as well as some in other areas, are granted by the federal government and administered by the Bureau of Land Management (the "BLM") and the Minerals Management Service (the "MMS") federal agencies. Operations conducted by the Company on federal oil and gas leases must comply with numerous statutory and regulatory restrictions concerning the above and other matters. Certain operations must be conducted pursuant to appropriate permits issued by the BLM and the MMS. MMS leases contain relatively standardized terms requiring compliance with detailed MMS regulations and, in the case of offshore leases, orders pursuant to the Outer Continental Shelf Lands Act ("OCSLA") (which are subject to change by the MMS). Such offshore operations are subject to numerous regulatory requirements, including the need for prior MMS approval for exploration, development, and production plans, stringent engineering and construction specifications applicable to offshore production facilities, regulations restricting the flaring or venting of production, and regulations governing the plugging and abandonment of offshore wells and the removal of all production facilities. Under certain circumstances, the MMS may require operations on federal leases to be suspended or terminated. Any such suspension or termination could adversely affect the Company's interests. The MMS has issued a notice of proposed rulemaking in which it proposes to amend its regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases. This proposed rule would modify the valuation procedures for both arm's length and non-arm's length crude oil transactions to decrease reliance on oil posted prices and assign a value to crude oil that, in the opinion of the MMS, better reflects its market value, establish a new MMS form for collecting differential data, and amend the valuation procedure for the sale of federal royalty oil. The Company cannot predict what action the MMS will take on this matter, nor can it predict how the Company will be affected by any change to this regulation. The MMS recently issued a final rule to clarify the types of costs that are deductible transportation costs for purposes of royalty valuation of production sold off the lease. In particular, the MMS will not allow deduction of costs associated with marketer fees, cash out and other pipeline imbalance penalties, or long-term storage fees. The Company cannot predict what, if any, effect the new rule will have on its operations. Sales of crude oil, condensate and natural gas liquids by the Company are made at unregulated market prices. 8
11 The transportation and sale for resale of natural gas in interstate commerce are regulated pursuant to the Natural Gas Act of 1938 (the "NGA") and the Natural Gas Policy Act of 1978 (the "NGPA"). These statutes are administered by the Federal Energy Regulatory Commission (the "FERC"). Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act of 1989 deregulated natural gas prices for all "first sales" of natural gas, which includes all sales by the Company of its own production. All other sales of natural gas by the Company, such as those of natural gas purchased from third parties, remain jurisdictional sales subject to a blanket sales certificate under the NGA, which has flexible terms and conditions. Consequently, all of the Company's sales of natural gas currently may be made at market prices, subject to applicable contract provisions. The Company's jurisdictional sales, however, are subject to the future possibility of greater federal oversight, including the possibility the FERC might prospectively impose more restrictive conditions on such sales. Since 1985, the FERC has endeavored to enhance competition in natural gas markets by making natural gas transportation more accessible to natural gas buyers and sellers on an open and nondiscriminatory basis. These efforts culminated in Order No. 636 and various rehearing orders ("Order No. 636"), which mandate a fundamental restructuring of interstate natural gas pipeline sales and transportation services, including the "unbundling" by interstate natural gas pipelines of the sales, transportation, storage, and other components of their service, and to separately state the rates for each unbundled service. The courts have largely affirmed the significant features of Order No. 636 and numerous related orders pertaining to the individual pipelines, although certain appeals remain pending and the FERC continues to review and modify its open access regulations. Order No. 636 does not directly regulate the Company's activities, but has an indirect effect because of its broad scope. Order No. 636 has ended interstate pipelines' traditional role as wholesalers of natural gas, and substantially increased competition in natural gas markets. In spite of this uncertainty, Order No. 636 may enhance the Company's ability to market and transport its natural gas production, although it may also subject the Company to more restrictive pipeline imbalance tolerances and greater penalties for violation of such tolerances. The Company owns, directly or indirectly, certain natural gas pipelines that it believes meet the traditional tests the FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction under the NGA. State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels as the pipeline restructuring under Order No. 636 is implemented. For example, the Texas Railroad Commission has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. The Company's gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. The Company's natural gas gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement, and management of facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. The Company cannot predict what effect, if any, such legislation might have on its operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes. The FERC has recently begun a broad review of its transportation regulations, including how they operate in conjunction with state proposals for retail gas marketing restructuring, whether to eliminate cost-of-service rates for short-term transportation, whether to allocate all short-term capacity on the basis of competitive auctions, and whether changes to its long-term transportation policies may also be appropriate to avail a market bias toward short-term contracts. While any resulting FERC action would affect the Company only indirectly, these inquiries are intended to further enhance competition in natural gas markets, while maintaining adequate consumer protections. The Company cannot predict the effect that any of the aforementioned orders or the challenges to such orders will ultimately have on the Company's operations. Additional proposals and proceedings that might 9
12 affect the natural gas industry are considered from time to time by Congress, the FERC and the courts. The Company cannot predict when or whether any such proposals or proceedings may become effective. It should also be noted that the natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less regulated approach currently being pursued by the FERC will continue indefinitely. Environmental Regulation. Various federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect the Company's operations and costs as a result of their effect on natural gas and crude oil exploration, development and production operations. Compliance with such laws and regulations has not had a material adverse effect on the Company's operations or financial condition. It is not anticipated, based on current laws and regulations, that the Company will be required in the near future to expend amounts that are material in relation to its total exploration and development expenditure program by reason of environmental laws and regulations, but inasmuch as such laws and regulations are frequently changed, the Company is unable to predict the ultimate cost of compliance. Canadian Regulation. In Canada, the petroleum industry is subject to extensive controls and operates under various provincial and federal legislation and regulations governing land tenure, royalties, taxes, production rates, operational standards, environmental protection, health and safety, exports and other matters. The Company operates within this regulatory framework and continues to monitor and evaluate the impact of the regulatory regime when determining parameters for engaging in oil and gas activities and investments in Canada. The price of natural gas and crude oil in Canada has been deregulated and is determined by market conditions and negotiations between buyers and sellers in a North American market place. The North American Free Trade Agreement supports the on-going cross-border commercial transactions of the natural gas and crude oil business. Various matters relating to the transportation and export of natural gas continue to be subject to regulation by provincial agencies and federally, by the National Energy Board; however, the North American Free Trade Agreement may have reduced the risk of altering existing cross-border commercial transactions through the assurance of fair implementation of regulatory changes, minimal disruption of contractual arrangements and the prohibition of discriminatory order restrictions and export taxes. Canadian governmental regulations may have a material effect on the economic parameters for engaging in oil and gas activities in Canada and may have a material effect on the advisability of investments in Canadian oil and gas drilling activities. The Company is monitoring political, regulatory and economic developments in Canada. Other International Regulation. The Company's exploration and production operations outside North America are subject to various types of regulations imposed by the respective governments of the countries in which the Company's operations are conducted, and may affect the Company's operations and costs within that country. The Company currently has producing operations offshore Trinidad and India and exploration, exploitation and development activities in other selected international areas. RELATIONSHIP BETWEEN THE COMPANY AND ENRON CORP. Ownership of Common Stock. Enron Corp. owns a majority of the outstanding shares of common stock of the Company. Through its ability to elect all of the directors of the Company, Enron Corp. generally has the ability to control matters relating to the management and policies of the Company, including determination with respect to acquisition or disposition of Company assets, the Company's exploration, development, and operating expenditure plans, future issuances of common stock or other securities of the Company and dividends payable on the common stock. (See also "General" relating to the announced intent by Enron Corp. to explore various potential transactions for its Company common stock.) Conflicts of Interest. The nature of the respective businesses of the Company and Enron Corp. and its other affiliates ("Enron") is such as to give rise to conflicts of interest between the companies from time to time. Conflicts may arise, for example, with respect to transactions involving purchases, sales and transportation of natural gas and other business dealings between the Company and Enron, potential acquisitions of 10
13 businesses or crude oil and natural gas properties or the payment of dividends by the Company. In connection with its finance and trading business conducted by its subsidiaries, Enron Capital & Trade Resources Corp. ("ECT") and Enron International Capital & Trade Corp. ("EICT"), Enron provides or arranges financing for others, including exploration and production companies, some of which compete with the Company. Enron may make investments in the debt or equity of such companies, may make loans secured by crude oil and natural gas properties or securities of crude oil and natural gas companies, may acquire production payments or may receive interests in crude oil and natural gas properties as equity components of lending transactions. As a result of its finance and trading business, Enron may also acquire crude oil and natural gas properties or companies upon foreclosure of secured loans or as part of a borrower's rearrangement of its obligations. Enron also has interests in entities such as Joint Energy Development Investments Limited Partnership, which makes debt and equity investments in energy-related businesses, including exploration and production companies. The acquisition, exploration, development and production activities of entities in which Enron has interests may directly or indirectly compete with the Company's business. Business Opportunity Agreement. In December 1997, Enron Corp. and the Company entered into an Equity Participation and Business Opportunity Agreement (the "Business Opportunity Agreement") that defines certain obligations that Enron owes to the Company and relieves Enron from certain obligations to the Company that it might otherwise have, including the obligation to offer certain business opportunities to the Company. Enron has advised the Company that, although it believes that it has conducted its business in a manner that is consistent with its duties as a majority shareholder of the Company, it was motivated to enter into the Business Opportunity Agreement because of the difficulty of determining the applicability of the law relating to duties that Enron may owe to the Company in connection with Enron's finance and trading business and because of Enron's desire to have more flexibility in pursuing business opportunities identified by or developed solely by Enron personnel. The Business Opportunity Agreement was approved by the Board of Directors of the Company after it was approved unanimously by a special committee of the Board of Directors consisting of the Company's independent directors. The special committee retained its own legal and financial advisers in connection with its evaluation of Enron's proposal, and the Business Opportunity Agreement as executed reflects significant concessions on Enron's part resulting from its negotiations with members of the special committee. The Business Opportunity Agreement provides generally that, so long as such activities are conducted in compliance with the Business Opportunity Agreement in all material respects, Enron may pursue business opportunities independently of the Company. The Business Opportunity Agreement contains an acknowledgment by the Company that Enron's finance and trading business may result in the acquisition by Enron of oil and gas properties or companies and that in certain cases Enron or entities in which Enron has an interest may acquire such assets pursuant to bidding or auction processes in which the Company is also a bidder. In the Business Opportunity Agreement, the Company acknowledges and agrees that such activities may have an impact on the Company or the price it pays for properties or securities it purchases from others, that Enron or entities in which it has an interest may acquire direct or indirect interests in oil and gas properties or companies as a result of such activities, may own, operate and control any such assets in connection therewith, and may acquire additional oil and gas properties or companies or pursue opportunities related thereto in connection therewith, in each case without any duty to offer all or any portion of such assets or opportunities to the Company. The Business Opportunity Agreement contains an acknowledgment and agreement by the Company that, to the extent that a court might hold that the conduct of such activity is a breach of a duty to the Company (and without admitting that the conduct of such activity is such a breach of duty), the Company waives any and all claims and causes of action that it may have to claim that the conduct of such activity is a breach of a duty to the Company. The Business Opportunity Agreement contains certain restrictions on the conduct of Enron's business. It also provides that, except with respect to business opportunities pursued jointly by Enron and the Company and except as otherwise agreed to between Enron and the Company, Enron's business will be conducted through the use of its own personnel and assets and not with the use of any personnel or assets of the Company. Thus, without the consent of the Company, the finance and trading business conducted by ECT, EICT or other Enron entities may only involve business opportunities identified by or presented to ECT 11
14 personnel, EICT personnel or other Enron personnel and developed and pursued solely through the use of the personnel and assets of ECT, EICT or other Enron entities. Enron has agreed that, so long as it controls the Company, it will not pursue any business opportunity a majority of the value of which involves oil and gas properties if the opportunity is first presented to an officer or director of Enron who is also an officer or director of the Company at the time such opportunity is presented, unless Enron first offers such opportunity to the Company. The Business Opportunity Agreement states that its provisions relate exclusively to the duties that Enron owes the Company and that nothing in the Business Opportunity Agreement affects the fiduciary or other duties owed to the Company by any individual director or officer of the Company in his or her capacity as such. In this connection, Enron has agreed that its representatives on the Board of Directors of the Company will not, for the purpose of enabling Enron to pursue an opportunity in the oil and gas business, vote in such a manner as to effectively prevent, prohibit or restrict the Company from pursuing such opportunity. In consideration for the Company's agreements in the Business Opportunity Agreement, Enron provided valuable consideration to the Company, including options to purchase common stock of Enron that will give the Company the opportunity to participate in future appreciation in value of Enron, including any appreciation in value resulting from activities that the Company has agreed to permit Enron and its subsidiaries to pursue. Enron granted the Company ten year options to purchase 3,200,000 shares of Enron common stock at $39.1875 per share, the closing price per share on the date that the Company's Board of Directors approved the Business Opportunity Agreement. The options vest in accordance with a schedule that provides that 25% vested immediately, 15% vest on the anniversary of the Business Opportunity Agreement in 1998 and 10% vest each anniversary thereafter until all of the options are vested. Vesting will be accelerated in the event of a change of control of the Company. For such purposes a "change of control" means that (a) Enron no longer owns capital stock of the Company representing at least 35% of the voting power for the election of directors and (b) a majority of the members of the Board of Directors of the Company consists of persons who are not officers or directors of Enron or any affiliate of Enron other than the Company. The Business Opportunity Agreement also included (i) an agreement to replace the existing services agreement, under which Enron provides certain services to the Company, with a new services agreement under which the Company's maximum payments to Enron for allocated indirect costs will be reduced by $2.8 million per year, (ii) an agreement by Enron relieving the Company of the obligation to bear the costs of any registration of sales by Enron of shares of common stock of the Company, (iii) an agreement by Enron to pay the costs of registration of the Company's sales of Enron common stock acquired upon exercise of the options granted in the Business Opportunity Agreement, (iv) an agreement that if Enron takes any action that results in the loss by the Company of its status as an "independent producer" under the Internal Revenue Code, Enron will pay the Company each year through 2006 the lesser of (a) $1 million and (b) an amount which, after payment of applicable taxes, will compensate the Company for the additional income tax liability resulting from the loss of independent producer status, (v) an agreement that if Enron requests that the Company relocate its offices, and if the Company agrees to do so, Enron will pay the Company's moving expenses, including expenses of building out or refurbishing the space in its new offices and expenses of removing and reinstalling the Company's telecommunications and information systems facilities and (vi) an agreement by Enron to reimburse the Company for the costs and expenses of legal and financial consultants retained to assist the special committee in connection with the Business Opportunity Agreement. In addition, pursuant to the Business Opportunity Agreement, Enron agreed to cause its subsidiary, Houston Pipe Line Company, to enter into various agreements with the Company rearranging certain existing contractual arrangements between them, and Enron and the Company entered into a licensing agreement covering the Enron name and mark and recognizing that the EOG and EOGI names and marks belong to the Company. In the Business Opportunity Agreement Enron and the Company also entered into agreements in principle regarding the manner in which they will share the burdens and benefits of the integrated projects under joint development by Enron and the Company in Qatar, Mozambique and Uzbekistan. The agreements in principle provide generally that the Company's interests in these projects will be 20%, 20% and 80%, respectively, of the combined ownership interest of the Company and Enron. In December 1998, the Company sold its interest in the Uzbekistan project and anticipates disposing of its interest in the Qatar project in early 1999. The Business Opportunity Agreement also contains provisions that give Enron the right to maintain its equity interest in the Company at certain levels. It provides that if the Company issues additional shares of its 12
15 capital stock Enron will have the right to purchase additional shares of capital stock of the Company as follows: (i) if Enron owns a majority interest, Enron will have the right to purchase sufficient shares to permit it to retain its majority interest; (ii) if Enron does not own a majority interest but accounts for the assets and operations of the Company on a consolidated basis for financial reporting purposes Enron will have the right to purchase sufficient shares to permit it to continue to account for the Company on a consolidated basis; and (iii) if Enron accounts for the assets and operations of the Company using the equity method for financial reporting purposes Enron will have the right to purchase sufficient shares to permit it to continue to account for the Company using the equity method. Any such purchase by Enron will be for cash at 97% of the average closing price per share over a specified 20 day period (reflecting a 3% private placement discount). Contractual Arrangements. As part of the Business Opportunity Agreement, the Company entered into a Services Agreement (the "Services Agreement") with Enron Corp. effective January 1, 1997, pursuant to which Enron Corp. provides various services, such as maintenance of certain employee benefit plans, provision of certain telecommunications and computer services, lease of certain office space and the provision of certain purchasing and operating services and certain other corporate staff and support services. Such services historically have been supplied to the Company by Enron Corp., and the Services Agreement provides for the further delivery of such services substantially identical in nature and quality to those services previously provided. The Company has agreed to a fixed rate for the rental of office space and to reimburse Enron Corp. for all other direct costs incurred in rendering services to the Company under the contract and to pay Enron Corp. for allocated indirect costs incurred in rendering such services up to a maximum of approximately $5.1 million for 1998 and $5.3 million for 1997. The limit on cost for the allocated indirect services provided by Enron Corp. to the Company will increase in subsequent years for inflation and certain changes in the Company's allocation bases. The Services Agreement is for an initial term of ten years through December 2006 and will continue thereafter until terminated by either party. In March 1995, in a series of transactions with Enron Corp., the Company exchanged all of its fuel supply and purchase contracts and related price swap agreements associated with a Texas City cogeneration plant (the "Cogen Contracts") for certain natural gas price swap agreements (the "Swap Agreements") of equivalent value. As a result of the transactions, the Company was relieved of all performance obligations associated with the Cogen Contracts. The Company will realize net operating revenues and receive corresponding cash payments of approximately $91 million during the period extending through December 31, 1999 under the terms of the Swap Agreements. The estimated fair value of the Swap Agreements was approximately $81 million at the date the Swap Agreements were received. The net effect of this series of transactions has resulted in increases in net operating revenues and cash receipts for the Company during 1995 and 1996 of approximately $13 million and $7 million, respectively, with offsetting decreases in 1998 and 1999 versus that anticipated under the Cogen Contracts. The Company and Enron Corp. have in the past entered into material intercompany transactions and agreements incident to their respective businesses, and they may be expected to enter into such transactions and agreements in the future. Such transactions and agreements have related to, among other things, the purchase and sale of natural gas and crude oil, hedging and trading activities, the financing of exploration and development efforts by the Company, and the provision of certain corporate services. (See "Marketing" and the Consolidated Financial Statements and notes thereto). The Company believes that its existing transactions and agreements with Enron Corp. have been at least as favorable to the Company as could be obtained from third parties, and the Company intends that the terms of any future transactions and agreements between the Company and Enron Corp. will be at least as favorable to the Company as could be obtained from third parties. OTHER MATTERS Energy Prices. Since the Company is primarily a natural gas company, it is more significantly impacted by changes in natural gas prices than in the prices for crude oil, condensate or natural gas liquids. During recent periods, domestic natural gas has been priced significantly below parity with crude oil and condensate based on the energy equivalency of, and differences in transportation and processing costs associated with, the respective products although that relationship improved during 1998. This imbalance in parity has been 13
16 primarily driven by, among other things, a supply of domestic natural gas volumes in excess of demand requirements. The Company is unable to predict when this supply imbalance may be resolved due to the significant impacts of factors such as general economic conditions, technology developments, weather and other international energy supplies over which the Company has no control. Average North America wellhead natural gas prices have fluctuated, at times rather dramatically, during the last three years. While these fluctuations resulted in increases in average North America wellhead natural gas prices received by the Company of 43% from 1995 to 1996 and 15% from 1996 to 1997, the average North America wellhead natural gas prices realized by the Company from 1997 to 1998 decreased by 15%. Wellhead natural gas volumes from Trinidad are sold at prices that are based on a fixed schedule with periodic escalations. Natural gas deliveries in India commenced in June 1997 and, under the terms of the production sharing contracts, the price of such deliveries are indexed to a basket of world market fuel oil quotations structured to include floor and ceiling limits. Due to the many uncertainties associated with the world political environment, the availabilities of other world wide energy supplies and the relative competitive relationships of the various energy sources in the view of the consumers, the Company is unable to predict what changes may occur in natural gas prices in the future. Substantially all of the Company's wellhead crude oil and condensate is sold under various terms and arrangements at market responsive prices. Crude oil and condensate prices also have fluctuated during the last three years. Due to the many uncertainties associated with the world political environment, the availabilities of other world wide energy supplies and the relative competitive relationships of the various energy sources in the view of the consumers, the Company is unable to predict what changes may occur in crude oil and condensate prices in the future. Risk Management. The Company engages in price risk management activities from time to time primarily for non-trading and to a lesser extent for trading purposes. Derivative financial instruments (primarily price swaps and costless collars) are utilized for non-trading purposes to hedge the impact of market fluctuations of natural gas and crude oil market prices on net income and cash flow. At December 31, 1998, the Company had outstanding crude oil commodity price swap transactions, designated as hedges, covering approximately 700 MBbl of crude oil and condensate for 1999. The fair value of the positions was a net revenue increase of $4 million at December 31, 1998. At December 31, 1998, based on the portion of the Company's anticipated natural gas volumes for 1999 for which prices have not, in effect, been hedged using NYMEX-related commodity market transactions and long-term marketing contracts, the Company's net income and cash flow sensitivity to changing natural gas prices is approximately $18 million for each $.10 per Mcf change in average wellhead natural gas prices. While the Company is not impacted as significantly by changing crude oil prices for those volumes not otherwise hedged, its net income and cash flow sensitivity is approximately $6 million for $1.00 per barrel change in average wellhead crude oil prices. Natural gas prices received in India fluctuate between floor and ceiling price limits based on prices for a basket of petroleum products. Tight Gas Sand Tax Credits (Section 29) and Severance Tax Exemption. United States federal tax law provides a tax credit for production of certain fuels produced from nonconventional sources (including natural gas produced from tight formations), subject to a number of limitations. Fuels qualifying for the credit must be produced from a well drilled or a facility placed in service after November 5, 1990 and before January 1, 1993, and must be sold before January 1, 2003. The credit, which is currently approximately $.52 per million British thermal units ("MMBtu") of natural gas, is computed by reference to the price of crude oil, and is phased out as the price of crude oil exceeds $23.50 in 1980 dollars (adjusted for inflation) with complete phaseout if such price exceeds $29.50 in 1980 dollars (similarly adjusted). Under this formula, the commencement of phaseout would be triggered if the average price for crude oil rose above approximately $48 per barrel in current dollars. Significant benefits from the tax credit have accrued and continue to accrue to the Company since a portion (and in some cases a substantial portion) of the Company's natural gas production from new wells drilled after November 5, 1990, 14
17 and before January 1, 1993, on the Company's leases in several of the Company's significant producing areas qualify for this tax credit. Natural gas production from wells spudded or completed after May 24, 1989 and before September 1, 1996 in tight formations in Texas qualifies for a ten-year exemption, ending August 31, 2001, from severance taxes, subject to certain limitations. In 1995, the drilling qualification period was extended in a modified and somewhat reduced form from September 1996 through August 2002. Consequently, new qualifying production will be added prospectively to that presently qualified. Other. All of the Company's natural gas and crude oil activities are subject to the risks normally incident to the exploration for and development and production of natural gas and crude oil, including blowouts, cratering and fires, each of which could result in damage to life and property. Offshore operations are subject to usual marine perils, including hurricanes and other adverse weather conditions, and governmental regulations as well as interruption or termination by governmental authorities based on environmental and other considerations. In accordance with customary industry practices, insurance is maintained by the Company against some, but not all, of the risks. Losses and liabilities arising from such events could reduce revenues and increase costs to the Company to the extent not covered by insurance. The Company's operations outside of North America are subject to certain risks, including expropriation of assets, risks of increases in taxes and government royalties, renegotiation of contracts with foreign governments, political instability, payment delays, limits on allowable levels of production and currency exchange and repatriation losses, as well as changes in laws, regulations and policies governing operations of foreign companies generally. 15
18 CURRENT EXECUTIVE OFFICERS OF THE REGISTRANT The current executive officers of the Company and their names and ages are as follows (all positions are with the Company unless otherwise noted): <TABLE> <CAPTION> NAME AGE POSITION ---- --- -------- <S> <C> <C> Forrest E. Hoglund.......... 65 Chairman of the Board; Director Mark G. Papa................ 52 President and Chief Executive Officer; Director Edmund P. Segner, III....... 45 Vice Chairman and Chief of Staff Dennis M. Ulak.............. 45 President, International Operations and Chairman of the Board and Chief Executive Officer, Enron Oil & Gas International, Inc. Jeffrey B. Sherrick......... 44 President and Chief Operating Officer, Enron Oil & Gas International, Inc. Loren M. Leiker............. 45 Executive Vice President, Exploration Gary L. Thomas.............. 49 Executive Vice President, North American Operations Barry Hunsaker, Jr.......... 48 Senior Vice President and General Counsel Walter C. Wilson............ 56 Senior Vice President and Chief Financial Officer </TABLE> Forrest E. Hoglund joined the Company as Chairman of the Board and Director in September 1987. He also served as Chief Executive Officer of the Company until September 1998 and served as President from May 1990 until December 1996. Mr. Hoglund is an advisory director of Chase Bank of Texas, National Association. Mark G. Papa was elected President and Chief Executive Officer and Director of the Company in September 1998, President and Chief Operating Officer in September 1997, President in December 1996 and was President North America Operations from February 1994 to September 1998. From May 1986 through January 1994, Mr. Papa served as Senior Vice President - Operations. Mr. Papa joined Belco Petroleum Corporation, a predecessor of the Company, in 1981. Edmund P. Segner, III became Vice Chairman and Chief of Staff of the Company in September 1997. Mr. Segner was a director of the Company from January 1997 to October 1997. Mr. Segner joined Enron Corp. in 1988 and was Executive Vice President and Chief of Staff. Dennis M. Ulak has been President - International Operations since January 1996 with responsibility for activities outside North America. Mr. Ulak also serves as Chairman and Chief Executive Officer of Enron Oil & Gas International, Inc. Mr. Ulak joined the Company in March 1987 as Senior Counsel and was named Assistant General Counsel for international operations in February 1989, Assistant General Counsel in August 1990 and Vice President and General Counsel in March 1992. Jeffrey B. Sherrick joined the Company in July 1989 and has been President and Chief Operating Officer of Enron Oil & Gas International, Inc., since September 1997. Mr. Sherrick was previously Senior Vice President, Acquisitions and Engineering of the Company. Loren M. Leiker joined the Company in April 1989 and has been Executive Vice President, Exploration since May 1998. Mr. Leiker was previously Senior Vice President, Exploration of the Company. Gary L. Thomas was elected Executive Vice President, North American Operations in May 1998. He was previously Senior Vice President and General Manager of the Company's Midland Division. Mr. Thomas joined a predecessor of the Company in July 1978. Barry Hunsaker, Jr. has been Senior Vice President and General Counsel since he joined the Company in May 1996. Prior to joining the Company, Mr. Hunsaker was a partner in the law firm of Vinson & Elkins L.L.P. Walter C. Wilson joined the Company in November 1987 and has been Senior Vice President and Chief Financial Officer since May 1991. 16
19 ITEM 2. PROPERTIES OIL AND GAS EXPLORATION AND PRODUCTION PROPERTIES AND RESERVES Reserve Information. For estimates of the Company's net proved and proved developed reserves of natural gas and liquids, including crude oil, condensate and natural gas liquids, see "Supplemental Information to Consolidated Financial Statements". There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth in Supplemental Information to Consolidated Financial Statements represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and liquids, including crude oil, condensate and natural gas liquids, that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the amount and quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers normally vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. In general, the volume of production from oil and gas properties owned by the Company declines as reserves are depleted. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration, exploitation and development activities, the proved reserves of the Company will decline as reserves are produced. Volumes generated from future activities of the Company are therefore highly dependent upon the level of success in finding or acquiring additional reserves and the costs incurred in so doing. The Company's estimates of reserves filed with other federal agencies agree with the information set forth in Supplemental Information to Consolidated Financial Statements. 17
20 Acreage. The following table summarizes the Company's developed and undeveloped acreage at December 31, 1998. Excluded is acreage in which the Company's interest is limited to owned royalty, overriding royalty and other similar interests. <TABLE> <CAPTION> DEVELOPED UNDEVELOPED TOTAL --------------------- --------------------- --------------------- GROSS NET GROSS NET GROSS NET --------- --------- --------- --------- --------- --------- <S> <C> <C> <C> <C> <C> <C> United States California.................... 21,324 16,747 821,738 748,238 843,062 764,985 Texas......................... 413,305 220,075 637,850 513,807 1,051,155 733,882 Offshore Gulf of Mexico....... 283,571 126,306 564,775 417,827 848,346 544,133 Wyoming....................... 153,597 116,092 324,531 251,792 478,128 367,884 Oklahoma...................... 188,963 104,633 122,848 87,264 311,811 191,897 Montana....................... 119,686 1,651 146,013 103,779 265,699 105,430 New Mexico.................... 71,945 35,091 106,133 64,232 178,078 99,323 Utah.......................... 74,454 50,311 40,873 27,205 115,327 77,516 Mississippi................... 5,144 5,052 43,174 42,950 48,318 48,002 Kansas........................ 17,339 15,489 6,747 4,009 24,086 19,498 Colorado...................... 20,619 1,233 30,908 13,618 51,527 14,851 Louisiana..................... 6,285 5,429 6,520 3,767 12,805 9,196 Arkansas...................... 8,522 1,319 2,457 2,010 10,979 3,329 Other......................... 5,247 984 1,015 795 6,262 1,779 --------- --------- --------- --------- --------- --------- Total................. 1,390,001 700,412 2,855,582 2,281,293 4,245,583 2,981,705 Canada Saskatchewan.................. 251,805 235,121 288,834 283,732 540,639 518,853 Alberta....................... 372,612 243,225 336,713 243,971 709,325 487,196 Manitoba...................... 11,743 9,954 23,730 21,966 35,473 31,920 British Columbia.............. 656 164 8,755 5,553 9,411 5,717 --------- --------- --------- --------- --------- --------- Total Canada.......... 636,816 488,464 658,032 555,222 1,294,848 1,043,686 Other International China......................... 5,000 5,000 1,844,531 1,844,531 1,849,531 1,849,531 Venezuela..................... - - 268,413 241,572 268,413 241,572 India......................... 98,300 29,490 564,307 169,292 662,607 198,782 France........................ - - 168,032 168,032 168,032 168,032 Trinidad...................... 4,200 3,990 147,233 143,490 151,433 147,480 --------- --------- --------- --------- --------- --------- Total Other International....... 107,500 38,480 2,992,516 2,566,917 3,100,016 2,605,397 --------- --------- --------- --------- --------- --------- Total................. 2,134,317 1,227,356 6,506,130 5,403,432 8,640,447 6,630,788 ========= ========= ========= ========= ========= ========= </TABLE> Producing Well Summary. The following table reflects the Company's ownership in gas and oil wells located in Texas, the Gulf of Mexico, Oklahoma, New Mexico, Utah, Wyoming, and various other states, Canada, Trinidad, India and China at December 31, 1998. Gross gas and oil wells include 255 with multiple completions. <TABLE> <CAPTION> PRODUCTIVE WELLS ----------------- GROSS NET ------- ------- <S> <C> <C> Gas......................................................... 5,253 3,788 Oil......................................................... 897 506 ----- ----- Total............................................. 6,150 4,294 ===== ===== </TABLE> 18
21 Drilling and Acquisition Activities. During the years ended December 31, 1998, 1997 and 1996 the Company spent approximately $769 million, $693 million and $599 million, respectively, for exploratory and development drilling and acquisition of leases and producing properties. The Company drilled, participated in the drilling of or acquired wells as set out in the table below for the periods indicated: <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, ------------------------------------------------ 1998 1997 1996 -------------- -------------- -------------- GROSS NET GROSS NET GROSS NET ----- ------ ----- ------ ----- ------ <S> <C> <C> <C> <C> <C> <C> Development Wells Completed North America Gas....................................... 478 402.80 467 352.90 396 325.04 Oil....................................... 38 34.98 94 74.85 80 57.46 Dry....................................... 79 62.16 101 80.01 80 68.77 --- ------ --- ------ --- ------ Total................................ 595 499.94 662 507.76 556 451.27 Outside North America Gas....................................... - - 12 3.60 - - Oil....................................... 21 6.30 6 1.80 1 .30 Dry....................................... - - - - - - --- ------ --- ------ --- ------ Total................................ 21 6.30 18 5.40 1 .30 --- ------ --- ------ --- ------ Total Development.................... 616 506.24 680 513.16 557 451.57 --- ------ --- ------ --- ------ Exploratory Wells Completed North America Gas....................................... 5 4.40 8 5.12 14 10.36 Oil....................................... 6 5.50 - - 1 .78 Dry....................................... 22 15.70 12 7.53 26 19.00 --- ------ --- ------ --- ------ Total................................ 33 25.60 20 12.65 41 30.14 Outside North America Gas....................................... 1 1.00 - - - - Oil....................................... 1 .90 - - - - Dry....................................... - - - - 1 .50 --- ------ --- ------ --- ------ Total................................ 2 1.90 - - 1 .50 --- ------ --- ------ --- ------ Total Exploratory.................... 35 27.50 20 12.65 42 30.64 --- ------ --- ------ --- ------ Total................................ 651 533.74 700 525.81 599 482.21 Wells in Progress at end of period............. 28 15.73 44 36.39 87 61.08 --- ------ --- ------ --- ------ Total................................ 679 549.47 744 562.20 686 543.29 === ====== === ====== === ====== Wells Acquired Gas....................................... 333 317.23* 227 82.45* 350 148.20* Oil....................................... - 1.70* 48 20.50* 5 .65 --- ------ --- ------ --- ------ Total................................ 333 318.93 275 102.95 355 148.85 === ====== === ====== === ====== </TABLE> - --------------- * Includes the acquisition of additional interests in certain wells in which the Company previously acquired an interest. All of the Company's drilling activities are conducted on a contract basis with independent drilling contractors. The Company owns no drilling equipment. 19
22 ITEM 3. LEGAL PROCEEDINGS The Company and its subsidiaries and related companies are named defendants in numerous lawsuits and named parties in numerous governmental proceedings arising in the ordinary course of business. While the outcome of lawsuits or other proceedings against the Company cannot be predicted with certainty, management does not expect these matters to have a material adverse effect on the financial condition or results of operations of the Company. Enron Oil & Gas India Ltd. ("EOGIL"), a wholly-owned subsidiary of the Company, is a respondent in two public interest lawsuits filed in the Delhi High Court, India. The first (the "Wadehra Action") was brought by B. L. Wadehra, an Indian public interest lawyer, against the Union of India, EOGIL, EOGIL co- participants in the Panna and Mukta fields, Reliance Industries Limited ("Reliance") and Oil & Natural Gas Corporation Limited ("ONGC"), and certain other respondents. ONGC is the Indian national oil company and is wholly-owned by the Union of India. The second suit (the "CPIL Action") was brought by the Centre for Public Interest Litigation and the National Alliance of People's Movement against the Union of India, the Central Bureau of Investigation, ONGC, Reliance and EOGIL. Petitioners in both the Wadehra Action and the CPIL Action allege various improprieties in the award of the Panna and Mukta fields to EOGIL, Reliance and ONGC, and seek the cancellation of the Production Sharing Contract for the Panna and Mukta fields. The Union of India is vigorously disputing these allegations. The Company believes that the public competitive bidding process for the fields was fair and that the award of these fields to EOGIL, Reliance and ONGC was proper. Following a series of hearings, the Delhi High Court has entered an order dismissing both lawsuits. The plaintiffs have filed a special leave petition seeking to appeal this decision to the India Supreme Court. Although no assurances can be given, based on currently available information the Company believes that the claims made by the petitioners in both actions are without merit, and that the ultimate resolution of these matters will not have a material adverse effect on its financial condition or results of operations. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS There were no matters submitted to a vote of security holders during the fourth quarter of 1998. 20
23 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS The following table sets forth, for the periods indicated, the high and low sales prices per share for the common stock of the Company, as reported on the New York Stock Exchange Composite Tape, and the amount of cash dividends paid per share. <TABLE> <CAPTION> PRICE RANGE --------------- CASH HIGH LOW DIVIDENDS ------ ------ --------- <S> <C> <C> <C> 1996 First Quarter............................................. $28.50 $22.38 $0.03 Second Quarter............................................ 28.63 23.88 0.03 Third Quarter............................................. 30.63 22.88 0.03 Fourth Quarter............................................ 28.38 23.25 0.03 1997 First Quarter............................................. $27.00 $19.88 $0.03 Second Quarter............................................ 21.75 17.50 0.03 Third Quarter............................................. 25.06 17.69 0.03 Fourth Quarter............................................ 23.81 18.50 0.03 1998 First Quarter............................................. $24.13 $18.56 $0.03 Second Quarter............................................ 24.50 18.13 0.03 Third Quarter............................................. 20.69 11.75 0.03 Fourth Quarter............................................ 18.50 12.69 0.03 </TABLE> As of March 1, 1999, there were approximately 440 record holders of the Company's common stock, including individual participants in security position listings. There are an estimated 22,000 beneficial owners of the Company's common stock, including shares held in street name. The Company currently intends to continue to pay quarterly cash dividends on its outstanding shares of common stock. However, the determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, the financial condition, funds from operations, level of exploration, exploitation and development expenditure opportunities and future business prospects of the Company. 21
24 ITEM 6. SELECTED FINANCIAL DATA <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, -------------------------------------------------------------- 1998 1997 1996 1995 1994 ---------- ---------- ---------- ---------- ---------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) <S> <C> <C> <C> <C> <C> STATEMENT OF INCOME DATA: Net operating revenues............ $ 769,188 $ 783,501 $ 730,648 $ 648,702 $ 625,823 Operating expenses Lease and well.................. 98,868 96,064 76,618 69,463 60,384 Exploration costs............... 65,940 57,696 55,009 42,044 41,811 Dry hole costs.................. 22,751 17,303 13,193 12,911 17,197 Impairment of unproved oil and gas properties............... 32,076 27,213 21,226 23,715 24,936 Depreciation, depletion and amortization................. 315,106 278,179 251,278 216,047 242,182 General and administrative...... 69,010 54,415 56,405 56,626 51,418 Taxes other than income......... 51,776 59,856 48,089 32,587 28,254 ---------- ---------- ---------- ---------- ---------- Total................... 655,527 590,726 521,818 453,393 466,182 ---------- ---------- ---------- ---------- ---------- Operating income.................. 113,661 192,775 208,830 195,309 159,641 Other income (expense), net....... (4,800) (1,588) (5,007) 669 2,783 Interest expense (net of interest capitalized).................... 48,579 27,717 12,861 11,924 8,489 ---------- ---------- ---------- ---------- ---------- Income before income taxes........ 60,282 163,470 190,962 184,054 153,935 Income tax provision(1)........... 4,111(2) 41,500(3) 50,954(4) 41,936(5) 5,937(6) ---------- ---------- ---------- ---------- ---------- Net income........................ $ 56,171 $ 121,970 $ 140,008 $ 142,118 $ 147,998 ========== ========== ========== ========== ========== Net income per share of common stock Basic........................... $ .36 $ .78 $ .88 $ .89 $ .93 ========== ========== ========== ========== ========== Diluted......................... $ .36 $ .77 $ .87 $ .88 $ .92 ========== ========== ========== ========== ========== Average number of common shares Basic........................... 154,345 157,376 159,853 159,917 159,845 ========== ========== ========== ========== ========== Diluted......................... 155,054 158,160 161,525 161,132 160,654 ========== ========== ========== ========== ========== </TABLE> <TABLE> <CAPTION> AT DECEMBER 31, -------------------------------------------------------------- 1998 1997 1996 1995 1994 ---------- ---------- ---------- ---------- ---------- (IN THOUSANDS) <S> <C> <C> <C> <C> <C> BALANCE SHEET DATA: Oil and gas properties - net..... $2,676,363 $2,387,207 $2,099,589 $1,881,545 $1,684,811 Total assets..................... 3,018,095 2,723,355 2,458,353 2,147,258 1,861,867 Long-term debt Trade.......................... 942,779 548,775 466,089 147,559 165,337 Affiliate...................... 200,000 192,500 - 141,520 25,000 Deferred revenue................. 4,198 39,918 56,383 205,453 184,183 Shareholders' equity............. 1,280,304 1,281,049 1,265,090 1,163,659 1,043,419 </TABLE> - --------------- (1) Includes benefits of approximately $12 million, $12 million, $16 million, $22 million and $36 million in 1998, 1997, 1996, 1995 and 1994, respectively, relating to tight gas sand federal income tax credits. (2) Includes a benefit of $2 million related to the final audit assessments of India taxes for certain prior years, a benefit of $3.8 million related to reduced deferred franchise taxes, and $3.5 million related to Venezuela deferred tax benefits. (3) Includes a benefit of $15 million primarily associated with the refiling of certain Canadian tax returns and the sale of certain international assets and subsidiaries. (4) Includes a benefit of $9 million primarily associated with a reassessment of deferred tax requirements and the successful resolution on audit of Canadian income taxes for certain prior years. (5) Includes a benefit of approximately $14 million associated with the successful resolution on audit of federal income taxes for certain prior years. (6) Includes a benefit of approximately $8 million related to reduced estimated state income taxes and certain franchise taxes, a portion of which is treated as income tax under Statement of Financial Accounting Standards ("SFAS") No. 109 - "Accounting for Income Taxes", and a $5 million benefit from the reduction of the Company's deferred federal income tax liability resulting from a reevaluation of deferred tax requirements. 22
25 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following review of operations for each of the three years in the period ended December 31, 1998 should be read in conjunction with the consolidated financial statements of the Company and notes thereto beginning with page F-1. RESULTS OF OPERATIONS Net Operating Revenues. Wellhead volume and price statistics for the specified years were as follows: <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, ------------------------ 1998 1997 1996 ------ ------ ------ <S> <C> <C> <C> Natural Gas Volumes (MMcf per day) United States(1).......................................... 671 657 608 Canada.................................................... 105 101 98 Trinidad.................................................. 139 113 124 India..................................................... 56 18 - ------ ------ ------ Total............................................. 971 889 830 ====== ====== ====== Average Natural Gas Prices ($/Mcf) United States(2).......................................... $ 1.93 $ 2.32 $ 2.04 Canada.................................................... 1.40 1.43 1.15 Trinidad.................................................. 1.06 1.05 1.00 India..................................................... 2.41 2.79 - Composite......................................... 1.78 2.07 1.78 Crude Oil and Condensate Volumes (MBbl per day) United States............................................. 14.0 11.7 9.2 Canada.................................................... 2.6 2.5 2.4 Trinidad.................................................. 3.0 3.4 5.2 India..................................................... 5.1 2.3 2.8 ------ ------ ------ Total............................................. 24.7 19.9 19.6 ====== ====== ====== Average Crude Oil and Condensate Prices ($/Bbl) United States............................................. $12.84 $19.81 $21.88 Canada.................................................... 11.82 17.16 18.01 Trinidad.................................................. 12.26 18.68 19.76 India..................................................... 12.86 20.05 20.17 Composite......................................... 12.66 19.30 20.60 Natural Gas Equivalent Volumes (MMcfe per day)(3) United States............................................. 771 743 670 Canada.................................................... 128 124 120 Trinidad.................................................. 157 133 156 India..................................................... 86 32 17 ------ ------ ------ Total............................................. 1,142 1,032 963 ====== ====== ====== Total Bcfe Deliveries............................. 417 377 353 </TABLE> - --------------- (1) Includes 48 MMcf per day in 1998, 1997 and 1996 delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended. Delivery obligations were terminated in December 1998. (2) Includes an average equivalent wellhead value of $1.53 per Mcf in 1998, $1.73 per Mcf in 1997, and $1.17 per Mcf in 1996 for the volumes detailed in note (1), net of transportation costs. (3) Includes natural gas and crude oil, condensate and natural gas liquids. 23
26 1998 compared to 1997. During 1998, net operating revenues decreased $14 million to $769 million. Total wellhead revenues of $755 million decreased by $74 million, or 9%, as compared to 1997. Average wellhead natural gas prices for 1998 were approximately 14% lower than the comparable period in 1997 reducing net operating revenues by approximately $104 million. Average wellhead crude oil and condensate prices were down by 34% worldwide decreasing net operating revenues by $60 million. Revenues from the sale of natural gas liquids decreased $6 million primarily due to lower wellhead prices. Wellhead natural gas volumes were approximately 9% higher than the comparable period in 1997 increasing net operating revenues by nearly $62 million. Natural gas production in India increased 38 MMcf per day from the Tapti and Panna fields, which did not commence deliveries until late in the second quarter of 1997 and the first quarter of 1998, respectively. Production in Trinidad increased 26 MMcf per day due primarily to additional volumes above the current contract level relating to gas balancing volumes pursuant to a field allocation agreement. North America wellhead natural gas production was approximately 2% higher than the comparable period in 1997. Wellhead crude oil and condensate volumes were 24% higher than in 1997 increasing net operating revenues by $34 million. Production from the Panna and Mukta fields in India more than doubled as a result of the ongoing development program and shut-down of crude oil production in the second quarter of 1997 to allow for the conversion from temporary to permanent production facilities. North America crude oil and condensate volumes increased 17% due primarily to higher levels of liquids production in South Texas and offshore. Other marketing activities associated with sales and purchases of natural gas, natural gas and crude oil price hedging and trading transactions, and margins related to the volumetric production payment decreased net operating revenue by $4 million during 1998, compared to a $61 million reduction in 1997, representing an improvement of $57 million. 1997 compared to 1996. During 1997, net operating revenues increased $53 million to $784 million. Total wellhead revenues of $828 million increased by $129 million, or 18%, as compared to 1996. Average wellhead natural gas prices for 1997 were up approximately 16% from the comparable period in 1996 increasing net operating revenues by approximately $82 million. Wellhead natural gas volumes were up 7% from 1996 adding net operating revenues of approximately $49 million. This is primarily attributable to a 7% increase in North America wellhead natural gas volumes and commencement of natural gas production from the Tapti field in India. Wellhead crude oil and condensate average prices decreased 6%, reducing net operating revenues by approximately $10 million from 1996. Wellhead crude oil and condensate volumes increased slightly from the comparable period a year ago and added approximately $2 million to net operating revenues as a 23% increase in North America wellhead crude oil and condensate volumes was partially offset by a natural decline in crude oil production from the Ibis field offshore Trinidad. Gains on the sales of reserves and related assets totaled $9 million in 1997 as compared to $20 million realized in 1996, reflecting a lower level of sales activity. Other marketing activities associated with sales and purchases of natural gas, natural gas and crude oil price hedging and trading transactions, and margins related to the volumetric production payment decreased net operating revenues by $61 million during 1997, compared to a $4 million increase in 1996. A $51 million revenue reduction related to natural gas commodity price hedging activities utilizing NYMEX-related commodity market transactions in 1997 partially offset greater wellhead price benefits noted above and compares to a $13 million revenue increase associated with similar transactions a year ago. A decrease in margins associated with sales and purchases of natural gas and the volumetric production payment reduced net revenues by approximately $9 million as compared to an $18 million addition in 1996, primarily resulting from higher costs of natural gas delivered in 1997. Additionally, the Company incurred a $5 million revenue reduction on its NYMEX-related crude oil price swap transactions in 1997 compared to a $13 million revenue reduction in 1996. 24
27 Operating Expenses 1998 compared to 1997. During 1998, operating expenses of $656 million were approximately $65 million higher than the $591 million incurred in 1997. Lease and well expenses increased $3 million to $99 million primarily due to commencement of operations in China. Exploration expenses of $66 million and dry hole expenses of $23 million increased $8 million and $5 million, respectively, from 1997 primarily due to increased exploratory drilling and other exploration activities in North America. Impairment of unproved oil and gas properties increased $5 million to $32 million resulting from a full year of impairment recorded on unproved leases acquired in 1997 in North America. Depreciation, depletion and amortization ("DD&A") expense increased approximately $37 million to $315 million in 1998 primarily reflecting a higher per unit rate in North America and increased worldwide production volumes. General and administrative expenses were $15 million higher than in 1997 due to expanded worldwide operations. Taxes other than income were down by approximately $8 million from the prior year primarily due to lower state severance taxes associated with decreased wellhead revenues in the United States. Total operating costs per unit of production, which include lease and well, DD&A, general and administrative, taxes other than income and interest expense, increased 2% to $1.40 per thousand cubic feet equivalent ("Mcfe") in 1998 from $1.37 per Mcfe in 1997. This increase is primarily due to a higher per unit rate of interest expense, DD&A expense and general and administrative expenses, partially offset by a lower per unit rate of lease and well expense and taxes other than income. 1997 compared to 1996. During 1997, operating expenses of $591 million were approximately $69 million higher than the $522 million incurred in 1996. Lease and well expenses increased $19 million to $96 million primarily due to expanded operations and increased North America production activities at higher costs to maximize the volumes delivered at higher product prices. Exploration expenses of $58 million and dry hole expenses of $17 million increased $3 million and $4 million, respectively, from 1996 primarily due to increased exploratory drilling activities in North America. Impairment of unproved oil and gas properties increased $6 million to $27 million as a result of increased acquisition of unproved leases in North America. DD&A expense increased approximately $27 million to $278 million in 1997 primarily reflecting an increase in North America production volumes. Taxes other than income were up by approximately $12 million from the prior year primarily due to higher state severance taxes associated with increased wellhead revenues in the United States. Total operating costs per unit of production, which include lease and well, DD&A, general and administrative, taxes other than income and interest expense, increased 9% to $1.37 per Mcfe in 1997 from $1.26 per Mcfe in 1996. This increase was primarily attributable to increased lease and well costs industry- wide, higher per unit DD&A and higher interest expense associated with expanded worldwide operations, partially offset by lower per unit general and administrative expenses. Other Income (Expense). The net expense for 1998 was primarily comprised of provisions for doubtful accounts receivable associated with certain international activities and contract settlements partially offset by interest income. Interest Expense. The increase in net interest expense of $21 million from 1997 to 1998 and $15 million from 1996 to 1997 primarily reflects a higher level of debt outstanding due to expanded worldwide operations and common stock repurchases. (See Note 4 to Consolidated Financial Statements.) Income Taxes. Income tax provision decreased approximately $37 million for 1998 as compared to 1997 and decreased approximately $9 million for 1997 as compared to 1996 primarily due to lower pre-tax income year to year. CAPITAL RESOURCES AND LIQUIDITY Cash Flow. The primary sources of cash for the Company during the three-year period ended December 31, 1998 included funds generated from operations, proceeds from the sales of selected oil and gas 25
28 reserves and related assets and proceeds from new borrowings. Primary cash outflows included funds used in operations, exploration and development expenditures, common stock repurchases, dividends paid to Company shareholders and the repayment of debt. Net operating cash flows of $404 million in 1998 decreased approximately $127 million as compared to 1997 primarily reflecting increased working capital for operating activities, higher interest expense, decreased operating revenues, increased cash operating expenses and increased cash taxes. Changes in working capital and other liabilities decreased operating cash flows by $72 million as compared to 1997 primarily due to the payment of $25 million of income taxes due under the 1997 tax agreement with Enron Corp. and changes in accounts receivable, accrued royalties payable and accrued production taxes caused by fluctuation of commodity prices at each year end. Net investing cash outflows of $760 million in 1998 increased by $63 million as compared to 1997 due primarily to increased exploration and development expenditures of $78 million, partially offset by higher proceeds from sales of reserves and related assets of $24 million. Changes in Components of Working Capital Associated with Investing Activities included for all periods changes in accounts payable related to the accrual of exploration and development expenditures and changes in inventories which represent materials and equipment used in drilling and related activities. Cash provided by financing activities in 1998 was $353 million as compared to $168 million in 1997. Financing activities in 1998 included the net issuance of $402 million of long-term debt primarily to fund exploration and development activities, to repurchase shares of the Company's common stock and to pay cash dividends. Share repurchases in 1998 totaled $26 million as compared to repurchases of $99 million in 1997. Dividend payments were approximately $19 million in each year. Net operating cash flows of $531 million in 1997 increased approximately $166 million as compared to 1996 due to higher production related net operating revenues net of cash operating expenses, lower current income taxes and reduced working capital requirements. The working capital changes primarily reflected higher 1996 end of year operating revenues collected in 1997 partially offset by the higher level of end of year 1996 operating-related accounts payable paid in 1997. Net investing cash outflows of $697 million in 1997 increased by approximately $185 million as compared to 1996 due primarily to increased exploration and development expenditures of approximately $93 million and reduced proceeds from sales of reserves and related assets of $26 million. The investing cash outflows in 1997 included a $22 million increase in working capital requirements associated with investing activities as compared to a $37 million decrease in 1996 primarily related to the timing of drilling expenditures. Cash provided by financing activities in 1997 increased $37 million, as compared to 1996, to $168 million. Financing activities in 1997 included the net issuance of $279 million of long-term debt as compared to $179 million issued in 1996. Share repurchases were $99 million in 1997 as compared to $44 million in 1996, and dividends paid were approximately $19 million in each year. Discretionary cash flow, a frequently used measure of performance for exploration and production companies, is generally derived by adjusting net income to eliminate the effects of depreciation, depletion and amortization, impairment of unproved oil and gas properties, deferred income taxes, gains on sales of oil and gas reserves and related assets, certain other non-cash amounts, except for amortization of deferred revenue, and exploration and dry hole costs. The Company generated discretionary cash flow of approximately $463 million in 1998, $508 million in 1997 and $479 million in 1996. Volumetric Production Payment. In September 1992, the Company sold a volumetric production payment for $326.8 million to a limited partnership. (See Note 5 to Consolidated Financial Statements.) Under the terms of the production payment, as amended October 1, 1993, the Company conveyed a real property interest of certain natural gas and other hydrocarbons to the purchaser. Deliveries were scheduled at the rate of 50 billion British thermal units per day through March 31, 1999. The Company accounted for the proceeds received in the transaction as deferred revenue, which was amortized into revenue and income as natural gas and other hydrocarbons were produced and delivered during the term of the volumetric production payment agreement. In December 1998, the Company settled the remainder of the contract in cash which was not materially different from the recorded deferred revenue, and delivery obligations were terminated. 26
29 Exploration and Development Expenditures. The table below sets out components of actual exploration and development expenditures for the years ended December 31, 1998, 1997 and 1996, along with those budgeted for the year 1999. <TABLE> <CAPTION> ACTUAL ------------------ BUDGETED EXPENDITURE CATEGORY 1998 1997 1996 1999 - -------------------- ---- ---- ---- --------- (IN MILLIONS) <S> <C> <C> <C> <C> Capital Drilling and Facilities................................... $421 $446 $408 Leasehold Acquisitions.................................... 36 77 45 Producing Property Acquisitions........................... 211 81 69 Capitalized Interest and Other............................ 22 22 18 ---- ---- ---- Subtotal.......................................... 690 626 540 Exploration Costs........................................... 66 58 55 Dry Hole Costs.............................................. 23 17 13 ---- ---- ---- Total............................................. $779 $701 $608 $575-$650 ==== ==== ==== ========= </TABLE> Exploration and development expenditures increased $78 million in 1998 as compared to 1997 primarily due to the third quarter 1998 acquisition of producing properties in the Gulf of Mexico for $156 million. Unproved leasehold acquisitions decreased $41 million primarily in North America. Drilling and facilities expenditures declined by approximately $25 million in 1998 as decreased activity in North America and lower expenditures in India were partially offset by new drilling in Trinidad and Venezuela. While development activities continued in India, expenditures in 1998 were less than in 1997 due to 1997 expenditures associated with the installation of permanent production facilities. Exploration and development expenditures increased $93 million in 1997 as compared to 1996 primarily due to increased exploration and development activities in the United States and the acquisition of producing properties in South Texas and in the Blackfoot area in Canada. Partially offsetting these increases were the reduction of construction expenditures in India related to the Tapti and Panna/Mukta production facilities which were completed in 1997. (See "Business - Exploration and Production" for additional information detailing the specific geographic locations of the Company's drilling programs and "Outlook" below for a discussion related to 1999 exploration and development expenditure plans). Hedging Transactions. The Company's 1998 NYMEX-related natural gas and crude oil commodity price swaps closed with "other marketing revenue" increases of $1 million pretax and $5 million pretax, respectively. At December 31, 1998, there were open crude oil commodity price swaps for 1999 covering approximately 700 MBbl of crude oil at a weighted average price of $18.85 per barrel. There were no outstanding natural gas commodity price swaps. Financing. The Company's long-term debt-to-total-capital ratio was 47% and 37% as of December 31, 1998 and 1997, respectively. During 1998, total long-term debt increased $402 million to $1,143 million as a result of borrowings related to increased exploration and development expenditures and the repurchase of the Company's common stock. (See Note 4 to the Consolidated Financial Statements). The estimated fair value of the Company's long-term debt at December 31, 1998 and 1997 was $1,141 million and $744 million, respectively, based upon quoted market prices and, where such prices were not available, upon interest rates currently available to the Company at year end. The Company's debt is primarily at fixed interest rates. At December 31, 1998, a 1% change in interest rates would result in a $49 million change in the estimated fair value of the fixed rate obligations. (See Note 14 to the Consolidated Financial Statements). Certain borrowings of the Company contain covenants requiring the maintenance of certain financial ratios and limitations on liens, debt issuance and dispositions of assets. These covenants include a 50% debt-to-total-capital limitation. Should commodity price levels experienced in late 1998 and early 1999 persist, the resulting reduction in cash flow available from 27
30 operations may necessitate further action(s) which could include a reduction in capital expenditure plans, the issuance of preferred stock and/or common equity, and/or the renegotiation of the debt covenants in order to remain in compliance. The Company maintains reciprocal agreements with Enron Corp. that provide for the borrowing by the Company of up to $200 million and investing by the Company of surplus funds of up to $200 million at market-based interest rates through December 31, 1999. Advances from Enron Corp. of $200 million and $193 million were outstanding as of December 31, 1998 and 1997, respectively. There were no investments with Enron Corp. as of December 31, 1998 or 1997. Outlook. Uncertainty continues to exist as to the direction of future North America natural gas and crude oil price trends, and there remains a rather wide divergence in the opinions held by some in the industry. This divergence in opinion is caused by various factors including improvements in the technology used in drilling and completing crude oil and natural gas wells that are tending to mitigate the impacts of fewer crude oil and natural gas wells being drilled, improvements being realized in the availability and utilization of natural gas storage capacity and warmer than normal weather experienced in 1998. However, the continually increasing recognition of natural gas as a more environmentally friendly source of energy along with the availability of significant domestically sourced supplies should result in further increases in demand and a supporting/strengthening of the overall natural gas market over time. Being primarily a natural gas producer, the Company is more significantly impacted by changes in natural gas prices than by changes in crude oil and condensate prices. (See "Business - Other Matters - Energy Prices"). At December 31, 1998, based on the portion of the Company's anticipated natural gas volumes for 1999 for which prices have not, in effect, been hedged using NYMEX-related commodity market transactions and long-term marketing contracts, the Company's net income and cash flow sensitivity to changing natural gas prices is approximately $18 million for each $.10 per Mcf change in average wellhead natural gas prices. While the Company is not impacted as significantly by changing crude oil prices for those volumes not otherwise hedged, its net income and cash flow sensitivity is approximately $6 million for $1.00 per barrel change in average wellhead crude oil prices. The Company plans to continue to focus a substantial portion of its development and exploration expenditures in its major producing areas in North America. However, based on the continuing uncertainty associated with North America natural gas prices and as a result of the recent success realized in Trinidad and India and commencement of development activities in China, the Company anticipates expending a substantial portion of its available funds in the further development of these opportunities outside North America. In addition, the Company expects to conduct limited exploratory activity in other areas outside of North America and will continue to evaluate the potential for involvement in other exploitation type opportunities. (See "Business - Exploration and Production" for additional information detailing the specific geographic locations of the related drilling programs). Budgeted 1999 expenditures are anticipated to be managed within the range of $575-$650 million, addressing the continuing uncertainty with regard to the future of the North America natural gas and crude oil and condensate price environment. Budgeted expenditures for 1999 are structured to maintain the flexibility necessary under the Company's continuing strategy of funding North America exploration, exploitation, development and acquisition activities primarily from available internally generated cash flow. The level of exploration and development expenditures may vary in 1999 and will vary in future periods depending on energy market conditions and other related economic factors. Based upon existing economic and market conditions, the Company believes net operating cash flow and available financing alternatives in 1999 will be sufficient to fund its net investing cash requirements for the year. However, the Company has significant flexibility with respect to its financing alternatives and adjustment of its exploration, exploitation, development and acquisition expenditure plans if circumstances warrant. While the Company has certain continuing commitments associated with expenditure plans related to operations in India, Trinidad, Venezuela and China, such commitments are not anticipated to be material when considered in relation to the total financial capacity of the Company. Other factors representing positive impacts continue to hold good potential for the Company in future periods. While the drilling qualification period for the tight gas sand federal income tax credit expired as of 28
31 December 31, 1992, the Company continued in 1998, and should continue in the future, to realize significant benefits associated with production from wells drilled during the qualifying period as it will be eligible for the federal income tax credit through the year 2002. However, the annual benefit, which was approximately $12 million in 1998 and is estimated to be approximately $8 million for 1999, is expected to continue to decline in future periods as production from the qualified wells declines. The drilling qualification period for a Texas severance tax exemption available on qualifying high cost natural gas revenues continued through August 1996 in its original form and is continuing in a modified and somewhat reduced form from that point through August 2002. Consequently, new qualifying production will be added prospectively to that presently qualified. (See "Business - Other Matters - Tight Gas Sand Tax Credits (Section 29) and Severance Tax Exemption"). Environmental Regulations. Various federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to protection of the environment, may affect the Company's operations and costs as a result of their effect on natural gas and crude oil exploration, exploitation, development and production operations. Compliance with such laws and regulations has not had a material adverse effect on the Company's operations or financial condition. It is not anticipated, based on current laws and regulations, that the Company will be required in the near future to expend amounts that are material in relation to its total exploration and development expenditure program by reason of environmental laws and regulations. However, inasmuch as such laws and regulations are frequently changed, the Company is unable to predict the ultimate cost of compliance. NEW ACCOUNTING PRONOUNCEMENT - SFAS NO. 133 In June 1998, the Financial Accounting Standards Board ("FASB") issued SFAS No. 133 - "Accounting for Derivative Instruments and Hedging Activities" effective for fiscal years beginning after June 15, 1999. The statement cannot be applied retroactively and must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts that were issued, acquired or substantively modified after December 31, 1997. The statement establishes accounting and reporting standards requiring that every derivative instrument be recorded in the balance sheet as either an asset or liability measured at its fair value. The statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the statements of income and requires a company to formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment. The Company has not yet quantified the impacts of adopting SFAS No. 133 on its financial statements and has not determined the timing of adoption. Based on the criteria of SFAS No. 133 and current interpretations thereof, the Company believes that the options it owns to purchase 3,200,000 Enron Corp. common shares, at a price of $39.1875 per share that expire in December 2007, qualify as derivative instruments. Accordingly, SFAS No. 133 would require the changes in the fair value of the options to be recognized currently in earnings. The Company cannot predict whether future interpretations currently being considered by the Emerging Issues Task Force of the FASB or potential amendments of SFAS No. 133 will result in the options being considered derivative instruments at the time of its adoption. At December 31, 1997, the carrying value of the options was approximately $23 million pre-tax, which represented the estimated fair value at the date of grant. At December 31, 1998, Enron Corp. common shares closed at $57.06 per share. Based on the Company's current level of other derivative and hedging activities, the Company does not expect the impact of adoption of SFAS No. 133 relative to those other activities to be material. 29
32 YEAR 2000 The Year 2000 problem generally results from the use in computer hardware and software of two digits rather than four digits to define the applicable year. When computer systems must process dates both before and after January 1, 2000, two-digit year "fields" may create processing ambiguities that can cause errors and system failures. For example, a date represented by "00" may be interpreted as referring to the year 1900, instead of 2000. The effects of the Year 2000 problem can be exacerbated by the interdependence of computer and telecommunications systems in the United States and throughout the world. This interdependence can affect the Company and its suppliers, trading partners, and customers, as well as governments of countries around the world where the Company does business. State of Readiness The Company Board of Directors has been briefed about the Year 2000 problem. The Board has adopted a Year 2000 Project (the "Project") aimed at preventing the Company's mission-critical functions from being impaired due to the Year 2000 problem. "Mission-critical" functions are those critical functions whose loss would cause an immediate stoppage of or significant impairment to core business processes (a core business process is one of material importance to the Company business). Implementation of the Project is directly supervised by a Year 2000 Oversight Committee, made up of four senior executives of the Company and its affiliates. Each operating division of the Company is implementing procedures specific to it that are part of the overall Project. The Company also has engaged certain outside consultants, technicians and other external resources to aid in formulating and implementing the Project. The Company is actively implementing the Project, which will be modified as events warrant. Under the Project, the Company will continue to inventory mission-critical computer hardware and software systems and embedded microprocessors (microprocessors with date-related functions, contained in a wide variety of devices), and software; assess the effects of Year 2000 problems on the mission-critical functions of the Company; remedy systems, software and embedded microprocessors in an effort to avoid material disruptions or other material adverse effects on mission-critical functions, processes and systems; verify and test the mission-critical systems to which remediation efforts have been applied; and attempt to mitigate those mission-critical aspects of the Year 2000 problem that are not remediated by January 1, 2000, including the development of contingency plans to cope with the mission-critical consequences of Year 2000 problems that have not been identified or remediated by that date. The Project recognizes that the computer, telecommunications, and other systems ("Outside Systems") of outside entities ("Outside Entities") have the potential for major, mission-critical, adverse effects on the conduct of Company business. The Company does not have control of these Outside Entities or Outside Systems. (In some cases, Outside Entities are U.S., state and local governmental organizations, foreign governments or businesses located in foreign countries.) However, the Project includes an ongoing process of identifying and contacting Outside Entities whose systems in the Company's judgment have, or may have, a substantial effect on the Company's ability to continue to conduct the mission-critical aspects of Company business without disruption from Year 2000 problems. The Project envisions the Company making an attempt to inventory and assess the extent to which these Outside Systems may not be "Year 2000 ready" or "Year 2000 compatible". The Company will attempt reasonably to coordinate with these Outside Entities in an ongoing effort to obtain assurance that the Outside Systems that are mission-critical will be Year 2000 compatible well before January 1, 2000. Consequently, the Company will work with Outside Entities in a reasonable attempt to inventory, assess, analyze, convert (where necessary), test, and develop contingency plans for connections to these mission-critical Outside Systems and to ascertain the extent to which they are, or can be made to be, Year 2000 ready and compatible with the Company's remediation of its own mission-critical systems. 30
33 As of March 1999, the Company is at various stages in implementation of the Project, as shown in the following tables. Any notation of "complete" conveys the fact only that the initial iteration of this phase has been substantially completed. All dates are only relevant for the initial iteration of the applicable stage of the Project. YEAR 2000 PROJECT READINESS <TABLE> <CAPTION> INVENTORY ASSESSMENT ANALYSIS CONVERSION TESTING Y2K-READY CONTINGENCY PLAN --------- ---------- -------- ---------- ------- --------- ---------------- <S> <C> <C> <C> <C> <C> <C> <C> Mission-Critical Internal Items.................. C IP IP IP IP IP IP Mission-Critical Outside Entities............... IP IP IP IP IP IP IP </TABLE> - --------------- Legend: C = Complete IP = In Process YEAR 2000 PROJECT ESTIMATED COMPLETION DATES <TABLE> <CAPTION> INVENTORY ASSESSMENT ANALYSIS CONVERSION TESTING Y2K-READY CONTINGENCY PLAN --------- ---------- -------- ---------- ------- --------- ---------------- <S> <C> <C> <C> <C> <C> <C> <C> Mission-Critical Internal Items.................. 12/98 3/99 3/99 6/99 9/99 9/99 9/99 Mission-Critical Outside Entities............... 3/99 6/99 6/99 9/99 9/99 9/99 9/99 </TABLE> It is important to recognize that the processes of inventorying, assessing, analyzing, converting (where necessary), testing, and developing contingency plans for mission-critical items in anticipation of the Year 2000 event may be iterative processes, requiring a repeat of some or all of these processes as the Company learns more about the Year 2000 problem and its effects on internal business information systems and on Outside Systems, and about the effects of embedded microprocessors on systems and business operations. The Company anticipates that it will continue with these processes through January 1, 2000 and on into the Year 2000 in order to assess and remediate problems that reasonably can be identified only after the start of the new century. The Project envisions verification and validation of certain mission-critical facilities and functions by independent consultants. These consultants will participate to varying degrees in many or all of the stages, including the inventory, assessment, and testing phases. Currently, the Company is utilizing Raytheon Engineers & Constructors, Inc. to assist Company personnel in the inventory and assessment phases of onshore and offshore and domestic and international operations. Costs to Address Year 2000 Issues The Company has not incurred material historical costs for Year 2000 awareness, inventory, assessment, analysis, conversion, testing, or contingency planning and anticipates that any future costs for these purposes, including those for implementing Year 2000 contingency plans, are not likely to be material. Although management believes that its estimates are reasonable, there can be no assurance, for the reasons stated in the "Summary" section below, that the actual costs of implementing the Project will not differ materially from the estimated costs or that the Company will not be materially adversely affected by Year 2000 issues. Year 2000 Risk Factors Regulatory requirements. Certain of the Company's operations are regulated by governmental authorities. The Company expects to satisfy these regulatory authority requirements for achieving Year 2000 readiness. If the Company's reasonable expectations in this regard are in error, and if a regulatory authority 31
34 should order the temporary cessation of operations in one or more of these areas, the adverse effect on the Company could be material. Outside Entities may face similar problems that materially adversely affect the Company. Shortage of Resources. Between now and 2000 it is anticipated that there will be increased competition for people with technical and managerial skills necessary to deal with the Year 2000 problem. While the Company is taking substantial precautions to recruit and retain sufficient people skilled in dealing with the Year 2000 problem, and has hired consultants who bring additional skilled people to deal with the Year 2000 problem, the Company could face shortages of skilled personnel or other resources, such as particular microprocessors or components containing Year 2000 ready microprocessors, and these shortages might delay or otherwise impair the Company's ability to assure that its mission-critical systems are Year 2000 ready. Outside Entities could face similar problems that materially adversely affect the Company. The Company believes that the possible impact of the shortage of skilled people and resources is not, and will not be, unique to the Company. Potential Shortcomings. The Company estimates that mission-critical systems, domestic and international, will be Year 2000-ready substantially before January 1, 2000. However, there is no assurance that the Project will succeed in accomplishing its purpose, or that unforeseen circumstances will not arise during implementation of the Project that would materially adversely affect the Company. Cascading Effect. The Company is taking reasonable steps to identify, assess, and, where appropriate, to replace devices that contain embedded microprocessors. Despite these reasonable efforts, the Company anticipates that it will not be able to find and remediate all embedded microprocessors in all systems. Further, it is anticipated that Outside Entities also will not be able to find and remediate all embedded microprocessors in their systems. Some of the embedded microprocessors that fail to operate or that produce anomalous results may create system disruptions or failures. Some of these disruptions or failures may spread from the systems in which they are located to other systems causing adverse effects upon the Company's ability to maintain safe operations, to serve its customers and otherwise to fulfill certain contractual and other legal obligations. The embedded microprocessor problem is widely recognized as one of the more difficult aspects of the Year 2000 problem across industries and throughout the world. The possible adverse impact of the embedded microprocessor problem is not, and will not be, unique to the Company. Third parties. The Company cannot assure that suppliers upon which it depends for essential goods and services will convert and test their mission-critical systems and processes in a timely manner. Failure or delay by all or some of these entities, including the U.S. and state or local governments and foreign governments, could create substantial disruptions having a material adverse effect on Company business. Contingency Plans As part of the Project, the Company is developing contingency plans that deal with, among others, two primary aspects of the Year 2000 problem: (1) that the Company, despite its good-faith, reasonable efforts, may not have satisfactorily remediated all internal, mission-critical systems; and (2) that Outside Systems may not be Year 2000 ready, despite the Company's good-faith, reasonable efforts to work with Outside Entities. These contingency plans are being designed to mitigate the disruptions or other adverse effects resulting from Year 2000 incompatibilities regarding these mission-critical functions or systems, and to facilitate the early identification and remediation of mission-critical Year 2000 problems that first manifest themselves after January 1, 2000. These contingency plans will contemplate an assessment of all mission-critical internal information technology systems and internal operational systems that use computer-based controls. This process will be pursued continuously into the Year 2000 as circumstances require. Further, the Company will in that time frame assess any mission-critical disruptions due to Year 2000-related failures that are external to the Company. These contingency plans include the creation, as deemed reasonably appropriate, of teams that will be standing by on the eve of the new millennium, prepared to respond rapidly and otherwise as necessary to 32
35 mission-critical Year 2000-related problems as soon as they become known. The composition of teams that are assigned to deal with Year 2000 problems will vary according to the nature, mission-criticality, and location of the problem. Because the Company operates internationally, some of its Year 2000 contingency teams will be located at mission-critical facilities overseas. Worst Case Scenario The Securities and Exchange Commission requires that public companies must forecast the most reasonably likely worst case Year 2000 scenario, assuming that the Company's Year 2000 plan is not effective. Analysis of the most reasonably likely worst case Year 2000 scenarios the Company may face leads to contemplation of the following possibilities which, though considered highly unlikely, must be included in any consideration of worst cases: widespread failure of electrical, natural gas, and similar supplies by utilities serving the Company domestically and internationally; widespread disruption of the services of communications common carriers domestically and internationally; similar disruption to means and modes of transportation for the Company and its employees, contractors, suppliers, and customers; significant disruption to the Company's ability to gain access to, and continue working in, office buildings and other facilities; the failure of substantial numbers of mission-critical hardware and software computer systems, including both internal business systems and systems (such as those with embedded microprocessors) controlling operational facilities such as electrical generation, transmission, and distribution systems and crude oil and natural gas plants and pipelines, domestically and internationally; and the failure, domestically and internationally, of Outside Systems, the effects of which would have a cumulative material adverse impact on the Company's mission-critical systems. Among other things, the Company could face substantial claims by customers for loss of revenues due to supply interruptions, inability to fulfill contractual obligations, inability to account for certain revenues or obligations or to bill or pay customers accurately and on a timely basis, and increased expenses associated with litigation, stabilization of operations following mission-critical failures, and the execution of contingency plans. The Company could also experience an inability by customers, traders, and others to pay, on a timely basis or at all, obligations owed to the Company. Under these circumstances, the adverse effect on the Company, and the diminution of Company revenues, could be material, although not quantifiable at this time. Further in this scenario, the cumulative effect of these failures could have a substantial adverse effect on the economy, domestically and internationally. The adverse effect on the Company, and the diminution of Company revenues, from a domestic or global recession or depression also could be material, although not quantifiable at this time. The Company will continue to monitor business conditions with the aim of assessing and quantifying material adverse effects, if any, that result or may result from the Year 2000 problem. Summary The Company has a plan to deal with the Year 2000 challenge and believes that it will be able to achieve substantial Year 2000 readiness with respect to the mission critical systems that it controls. From a forward-looking perspective, the extent and magnitude of the Year 2000 problem as it will affect the Company, both before and for some period after January 1, 2000, are difficult to predict or quantify for a number of reasons. Among these are: the difficulty of locating "embedded" microprocessors that may be in a great variety of mission-critical hardware used for process or flow control, environmental, transportation, access, communications, and other systems; the difficulty of inventorying, assessing, remediating, verifying and testing, Outside Systems connected, and vital, to the Company's computer, telecommunications, or other mission-critical systems; the difficulty of locating all mission-critical software (computer code) that is not Year 2000 compatible; and the unavailability of certain necessary internal or external resources, including but not limited to trained hardware and software engineers, technicians, and other personnel to perform adequate remediation, verification, and testing of mission-critical Company systems or Outside Systems. Year 2000 costs are difficult to estimate accurately because of unanticipated vendor delays, technical difficulties, the impact of tests of Outside Systems, and similar events. There can be no assurance for example that all Outside Systems with a mission-critical impact will be adequately remediated so that they are Year 2000 ready by January 1, 2000, or by some earlier date, so as not to create a material disruption to the Company's business. If, despite reasonable 33
36 efforts under the Year 2000 Project, there are mission-critical Year 2000-related failures that create substantial disruptions to Company business, the adverse impact on the Company could be material. Additionally, Year 2000 costs are difficult to estimate accurately because of unanticipated vendor delays, technical difficulties, the impact of tests of Outside Systems and similar events. Moreover, despite the Company's belief that costs for implementing the Project will not be material, the estimated costs of implementing the Project do not take into account the costs, if any, that might be incurred as a result of Year 2000-related failures that occur despite implementation of the Project. INFORMATION REGARDING FORWARD LOOKING STATEMENTS This Annual Report on Form 10-K includes forward looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Although the Company believes that its expectations are based on reasonable assumptions, it can give no assurance that such expectations will be achieved. Important factors that could cause actual results to differ materially from those in the forward looking statements herein include, but are not limited to, the timing and extent of changes in commodity prices for crude oil, natural gas and related products and interest rates; the extent of the Company's success in discovering, developing, marketing and producing reserves and in acquiring oil and gas properties; the Company's success in implementing its Year 2000 Plan, the effectiveness of the Company's Year 2000 Plan, and the Year 2000 readiness of Outside Entities; political developments around the world and conditions of the capital and equity markets during the periods covered by the forward looking statements. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Company's exposure to interest rate risk and commodity price risk is discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Financing" and "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Outlook", respectively. The Company's exposure to foreign currency exchange rate risks and other market risks is insignificant. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required hereunder is included in this report as set forth in the "Index to Financial Statements" on page F-1. ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by this Item regarding directors is set forth in the Proxy Statement under the caption entitled "Election of Directors", and is incorporated herein by reference. See list of "Current Executive Officers of the Registrant" in Part I located elsewhere herein. There are no family relationships among the officers listed, and there are no arrangements or understandings pursuant to which any of them were elected as officers. Officers are appointed or elected annually by the Board of Directors at its first meeting following the Annual Meeting of Shareholders, each to hold office until the corresponding meeting of the Board in the next year or until a successor shall have been elected, appointed or shall have qualified. 34
37 ITEM 11. EXECUTIVE COMPENSATION The information required by this Item is set forth in the Proxy Statement under the caption "Compensation of Directors and Executive Officers", and is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by this Item is set forth in the Proxy Statement under the captions "Election of Directors" and "Compensation of Directors and Executive Officers", and is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information required by this Item is set forth in the Proxy Statement under the caption "Certain Transactions", and is incorporated herein by reference. PART IV ITEM 14.FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE, EXHIBITS AND REPORTS ON FORM 8-K (A)(1) AND (2) FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE See "Index to Financial Statements" set forth on page F-1. (A)(3) EXHIBITS See pages E-1 through E-5 for a listing of the exhibits. (B) REPORTS ON FORM 8-K The Company filed a Report on Form 8-K on April 17, 1998 reporting the sale on April 8, 1998 of $150 million principal amount of 6.65% Notes due April 1, 2028 pursuant to an underwritten public offering. The Company filed a Report on Form 8-K on December 24, 1998 reporting the sale on December 14, 1998 of $175 million principal amount of 6.00% Notes due December 15, 2008 pursuant to an underwritten public offering. 35
38 ENRON OIL & GAS COMPANY INDEX TO FINANCIAL STATEMENTS <TABLE> <CAPTION> PAGE ---- <S> <C> Consolidated Financial Statements: Management's Responsibility for Financial Reporting....... F-2 Report of Independent Public Accountants.................. F-3 Consolidated Statements of Income and Comprehensive Income for Each of the Three Years in the Period Ended December 31, 1998...................................... F-4 Consolidated Balance Sheets - December 31, 1998 and 1997................................................... F-5 Consolidated Statements of Shareholders' Equity for Each of the Three Years in the Period Ended December 31, 1998................................................... F-6 Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 1998...... F-7 Notes to Consolidated Financial Statements................ F-8 Supplemental Information to Consolidated Financial Statements................................................ F-25 Financial Statement Schedule: Schedule II - Valuation and Qualifying Accounts and Reserves.................................................. S-1 </TABLE> Other financial statement schedules have been omitted because they are inapplicable or the information required therein is included elsewhere in the consolidated financial statements or notes thereto. F-1
39 MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING The following consolidated financial statements of Enron Oil & Gas Company and its subsidiaries were prepared by management, which is responsible for their integrity, objectivity and fair presentation. The statements have been prepared in conformity with generally accepted accounting principles and, accordingly, include some amounts that are based on the best estimates and judgments of management. Arthur Andersen LLP, independent public accountants, was engaged to audit the consolidated financial statements of Enron Oil & Gas Company and its subsidiaries and issue a report thereon. In the conduct of the audit, Arthur Andersen LLP was given unrestricted access to all financial records and related data including minutes of all meetings of shareholders, the Board of Directors and committees of the Board. Management believes that all representations made to Arthur Andersen LLP during the audit were valid and appropriate. The system of internal controls of Enron Oil & Gas Company and its subsidiaries is designed to provide reasonable assurance as to the reliability of financial statements and the protection of assets from unauthorized acquisition, use or disposition. This system includes, but is not limited to, written policies and guidelines including a published code for the conduct of business affairs, conflicts of interest and compliance with laws regarding antitrust, antiboycott and foreign corrupt practices policies, the careful selection and training of qualified personnel, and a documented organizational structure outlining the separation of responsibilities among management representatives and staff groups. The adequacy of financial controls of Enron Oil & Gas Company and its subsidiaries and the accounting principles employed in financial reporting by the Company are under the general oversight of the Audit Committee of the Board of Directors. No member of this committee is an officer or employee of the Company. The independent public accountants and internal auditors have direct access to the Audit Committee and meet with the committee from time to time to discuss accounting, auditing and financial reporting matters. It should be recognized that there are inherent limitations to the effectiveness of any system of internal control, including the possibility of human error and circumvention or override. Accordingly, even an effective system can provide only reasonable assurance with respect to the preparation of reliable financial statements and safeguarding of assets. Furthermore, the effectiveness of an internal control system can change with circumstances. It is management's opinion that, considering the criteria for effective internal control over financial reporting and safeguarding of assets which consists of interrelated components including the control environment, risk assessment process, control activities, information and communication systems, and monitoring, the Company maintained an effective system of internal control as to the reliability of financial statements and the protection of assets against unauthorized acquisition, use or disposition during the year ended December 31, 1998. <TABLE> <S> <C> WALTER C. WILSON MARK G. PAPA Senior Vice President and President and Chief Financial Officer Chief Executive Officer </TABLE> Houston, Texas March 5, 1999 F-2
40 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To Enron Oil & Gas Company: We have audited the accompanying consolidated balance sheets of Enron Oil & Gas Company (a Delaware corporation) and subsidiaries as of December 31, 1998 and 1997, and the related consolidated statements of income and comprehensive income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 1998. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and the schedule based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Enron Oil & Gas Company and subsidiaries as of December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The financial statement schedule listed in the index to financial statements is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. ARTHUR ANDERSEN LLP Houston, Texas March 5, 1999 F-3
41 ENRON OIL & GAS COMPANY CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, ------------------------------ 1998 1997 1996 -------- -------- -------- <S> <C> <C> <C> NET OPERATING REVENUES Natural Gas Trade.................................................. $558,376 $544,181 $393,129 Associated Companies................................... 62,929 71,339 164,745 Crude Oil, Condensate and Natural Gas Liquids Trade.................................................. 120,366 121,838 108,365 Associated Companies................................... 9,266 29,951 37,539 Gains on Sales of Reserves and Related Assets and Other, Net.................................................... 18,251 16,192 26,870 -------- -------- -------- Total............................................. 769,188 783,501 730,648 OPERATING EXPENSES Lease and Well............................................ 98,868 96,064 76,618 Exploration Costs......................................... 65,940 57,696 55,009 Dry Hole Costs............................................ 22,751 17,303 13,193 Impairment of Unproved Oil and Gas Properties............. 32,076 27,213 21,226 Depreciation, Depletion and Amortization.................. 315,106 278,179 251,278 General and Administrative................................ 69,010 54,415 56,405 Taxes Other Than Income................................... 51,776 59,856 48,089 -------- -------- -------- Total............................................. 655,527 590,726 521,818 -------- -------- -------- OPERATING INCOME............................................ 113,661 192,775 208,830 OTHER INCOME (EXPENSE), NET................................. (4,800) (1,588) (5,007) -------- -------- -------- INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES............. 108,861 191,187 203,823 INTEREST EXPENSE Incurred Trade.................................................. 60,701 41,399 20,383 Affiliate.............................................. 589 24 1,614 Capitalized............................................... (12,711) (13,706) (9,136) -------- -------- -------- Net Interest Expense................................... 48,579 27,717 12,861 -------- -------- -------- INCOME BEFORE INCOME TAXES.................................. 60,282 163,470 190,962 INCOME TAX PROVISION........................................ 4,111 41,500 50,954 -------- -------- -------- NET INCOME.................................................. 56,171 121,970 140,008 OTHER COMPREHENSIVE INCOME (LOSS) Foreign Currency Translation Adjustment................... (16,077) (9,592) 568 -------- -------- -------- COMPREHENSIVE INCOME........................................ $ 40,094 $112,378 $140,576 ======== ======== ======== NET INCOME PER SHARE OF COMMON STOCK Basic..................................................... $ .36 $ .78 $ .88 ======== ======== ======== Diluted................................................... $ .36 $ .77 $ .87 ======== ======== ======== AVERAGE NUMBER OF COMMON SHARES Basic..................................................... 154,345 157,376 159,853 ======== ======== ======== Diluted................................................... 155,054 158,160 161,525 ======== ======== ======== </TABLE> The accompanying notes are an integral part of these consolidated financial statements. F-4
42 ENRON OIL & GAS COMPANY CONSOLIDATED BALANCE SHEETS (IN THOUSANDS) ASSETS <TABLE> <CAPTION> AT DECEMBER 31, ------------------------- 1998 1997 ----------- ----------- <S> <C> <C> CURRENT ASSETS Cash and Cash Equivalents................................. $ 6,303 $ 9,330 Accounts Receivable Trade.................................................. 176,608 185,979 Associated Companies................................... 16,980 46,120 Inventories............................................... 39,581 32,040 Other..................................................... 6,878 8,566 ----------- ----------- Total............................................. 246,350 282,035 OIL AND GAS PROPERTIES (Successful Efforts Method).......... 4,814,425 4,291,405 Less: Accumulated Depreciation, Depletion and Amortization........................................... (2,138,062) (1,904,198) ----------- ----------- Net Oil and Gas Properties............................. 2,676,363 2,387,207 OTHER ASSETS................................................ 95,382 54,113 ----------- ----------- TOTAL ASSETS...................................... $ 3,018,095 $ 2,723,355 =========== =========== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Accounts Payable Trade.................................................. $ 159,690 $ 198,109 Associated Companies................................... 46,597 37,613 Accrued Taxes Payable..................................... 20,087 28,841 Dividends Payable......................................... 4,710 4,705 Other..................................................... 31,550 21,729 ----------- ----------- Total............................................. 262,634 290,997 LONG-TERM DEBT Trade..................................................... 942,779 548,775 Affiliate................................................. 200,000 192,500 OTHER LIABILITIES Trade..................................................... 21,516 37,739 Associated Companies...................................... 46,327 44,699 DEFERRED INCOME TAXES....................................... 260,337 287,678 DEFERRED REVENUE............................................ 4,198 39,918 COMMITMENTS AND CONTINGENCIES (Note 9) SHAREHOLDERS' EQUITY Common Stock, $.01 Par, 320,000,000 shares Authorized and 160,000,000 shares Issued.............................. 201,600 201,600 Additional Paid In Capital................................ 401,524 402,877 Unearned Compensation..................................... (4,900) (4,694) Cumulative Foreign Currency Translation Adjustment........ (35,848) (19,771) Retained Earnings......................................... 838,371 800,709 Common Stock Held in Treasury, 6,276,156 shares at December 31, 1998 and 4,935,744 shares at December 31, 1997................................................... (120,443) (99,672) ----------- ----------- Total Shareholders' Equity........................ 1,280,304 1,281,049 ----------- ----------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY........ $ 3,018,095 $ 2,723,355 =========== =========== </TABLE> The accompanying notes are an integral part of these consolidated financial statements. F-5
43 ENRON OIL & GAS COMPANY CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) <TABLE> <CAPTION> CUMULATIVE FOREIGN COMMON ADDITIONAL CURRENCY STOCK TOTAL COMMON PAID IN UNEARNED TRANSLATION RETAINED HELD IN SHAREHOLDERS' STOCK CAPITAL COMPENSATION ADJUSTMENT EARNINGS TREASURY EQUITY -------- ---------- ------------ ----------- -------- --------- ------------- <S> <C> <C> <C> <C> <C> <C> <C> Balance at December 31, 1995.......... $201,600 $399,379 $ - $(10,747) $576,740 $ (3,313) $1,163,659 Net Income.......................... - - - - 140,008 - 140,008 Dividends Paid/Declared, $.12 Per Share............................. - - - - (19,184) - (19,184) Translation Adjustment.............. - - - 568 - - 568 Treasury Stock Purchased/ Tendered.......................... - - - - - (63,004) (63,004) Treasury Stock Issued Under Stock Plans............................. - (11,167) (7,085) - - 59,937 41,685 Amortization of Unearned Compensation...................... - - 1,358 - - - 1,358 -------- -------- ------- -------- -------- --------- ---------- Balance at December 31, 1996.......... 201,600 388,212 (5,727) (10,179) 697,564 (6,380) 1,265,090 Net Income.......................... - - - - 121,970 - 121,970 Dividends Paid/Declared, $.12 Per Share............................. - - - - (18,825) - (18,825) Translation Adjustment.............. - - - (9,592) - - (9,592) Treasury Stock Purchased............ - - - - - (99,306) (99,306) Treasury Stock Issued Under Stock Plans............................. - (872) - - - 6,014 5,142 Options Granted by Enron Corp....... - 15,081 - - - - 15,081 Amortization of Unearned Compensation...................... - - 1,033 - - - 1,033 Other............................... - 456 - - - - 456 -------- -------- ------- -------- -------- --------- ---------- Balance at December 31, 1997.......... 201,600 402,877 (4,694) (19,771) 800,709 (99,672) 1,281,049 Net Income.......................... - - - - 56,171 - 56,171 Dividends Paid/Declared, $.12 Per Share............................. - - - - (18,509) - (18,509) Translation Adjustment.............. - - - (16,077) - - (16,077) Treasury Stock Purchased............ - - - - - (25,875) (25,875) Treasury Stock Issued Under Stock Plans............................. - (492) (1,709) - - 5,104 2,903 Amortization of Unearned Compensation...................... - - 1,503 - - - 1,503 Other............................... - (861) - - - - (861) -------- -------- ------- -------- -------- --------- ---------- Balance at December 31, 1998.......... $201,600 $401,524 $(4,900) $(35,848) $838,371 $(120,443) $1,280,304 ======== ======== ======= ======== ======== ========= ========== </TABLE> The accompanying notes are an integral part of these consolidated financial statements. F-6
44 ENRON OIL & GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS) <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, --------------------------------- 1998 1997 1996 --------- --------- --------- <S> <C> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES Reconciliation of Net Income to Net Operating Cash Inflows: Net Income................................................ $ 56,171 $ 121,970 $ 140,008 Items Not Requiring (Providing) Cash Depreciation, Depletion and Amortization............... 315,106 278,179 251,278 Impairment of Unproved Oil and Gas Properties.......... 32,076 27,213 21,226 Deferred Income Taxes.................................. (26,794) 16,665 2,276 Other, Net............................................. 7,761 359 7,830 Exploration Costs......................................... 65,940 57,696 55,009 Dry Hole Costs............................................ 22,751 17,303 13,193 Gains On Sales of Reserves and Related Assets and Other, Net.................................................... (11,191) (9,287) (20,358) Other, Net................................................ 1,116 (2,590) 8,871 Changes in Components of Working Capital and Other Liabilities Accounts Receivable.................................... 36,363 48,893 (120,370) Inventories............................................ (7,541) (11,294) (9,049) Accounts Payable....................................... (65,249) (11,478) 87,495 Accrued Taxes Payable.................................. (8,754) 10,287 (1,041) Other Liabilities...................................... 2,324 2,521 3,752 Other, Net............................................. (3,620) 9,760 270 Amortization of Deferred Revenue.......................... (43,344) (43,345) (43,463) Changes in Components of Working Capital Associated with Investing and Financing Activities..................... 30,491 18,077 (31,817) --------- --------- --------- NET OPERATING CASH INFLOWS.................................. 403,606 530,929 365,110 INVESTING CASH FLOWS Additions to Oil and Gas Properties....................... (690,352) (626,198) (539,330) Exploration Costs......................................... (65,940) (57,696) (55,009) Dry Hole Costs............................................ (22,751) (17,303) (13,193) Proceeds from Sales of Reserves and Related Assets........ 61,858 37,521 63,951 Changes in Components of Working Capital Associated with Investing Activities................................... (30,173) (22,454) 37,402 Other, Net................................................ (12,262) (11,000) (5,381) --------- --------- --------- NET INVESTING CASH OUTFLOWS................................. (759,620) (697,130) (511,560) FINANCING CASH FLOWS Long-Term Debt Trade.................................................. 394,004 86,595 320,580 Affiliate.............................................. 7,500 192,500 (141,520) Dividends Paid............................................ (18,504) (18,938) (19,161) Treasury Stock Purchased.................................. (25,875) (99,306) (43,507) Proceeds from Sales of Treasury Stock..................... 2,883 5,141 22,188 Other, Net................................................ (7,021) 1,895 (7,525) --------- --------- --------- NET FINANCING CASH INFLOWS.................................. 352,987 167,887 131,055 --------- --------- --------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............ (3,027) 1,686 (15,395) CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR.............. 9,330 7,644 23,039 --------- --------- --------- CASH AND CASH EQUIVALENTS AT END OF YEAR.................... $ 6,303 $ 9,330 $ 7,644 ========= ========= ========= </TABLE> The accompanying notes are an integral part of these consolidated financial statements. F-7
45 ENRON OIL & GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED) 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation. The consolidated financial statements of Enron Oil & Gas Company (the "Company"), 54% of the outstanding common stock of which was owned by Enron Corp. as of December 31, 1998, include the accounts of all domestic and foreign subsidiaries. All material intercompany accounts and transactions have been eliminated. Certain reclassifications have been made to the consolidated financial statements for prior years to conform with the current presentation. The preparation of 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 revenue and expenses during the reporting period. Actual results could differ from those estimates. Cash and Cash Equivalents. The Company records as cash equivalents all highly liquid short-term investments with original maturities of three months or less. The Company had approximately $32 million of outstanding checks payable classified as accounts payable at December 31, 1998. Oil and Gas Operations. The Company accounts for its natural gas and crude oil exploration and production activities under the successful efforts method of accounting. Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. Amortization of any remaining costs of such leases begins at a point prior to the end of the lease term depending upon the length of such term. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience, is amortized over the average holding period. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred. Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of natural gas and crude oil, are capitalized. Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. Estimated future dismantlement, restoration and abandonment costs (classified as long-term liabilities), net of salvage values, are taken into account. Certain other assets are depreciated on a straight-line basis. In the first quarter of 1996, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 121 - "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of". Periodically, or when circumstances indicate that an asset may be impaired, the Company compares expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on the Company's estimate of future crude oil and natural gas prices and operating costs, and anticipated production from proved and risk-adjusted probable and possible reserves, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Since the adoption of SFAS No. 121, the Company has recorded non-cash impairment charges that were immaterial to and included in depreciation, depletion and amortization expense. F-8
46 Inventories, consisting primarily of tubular goods and well equipment held for use in the exploration for, and development and production of natural gas and crude oil reserves, are carried at cost with adjustments made from time to time to recognize changes in condition value. Natural gas revenues are recorded on the entitlement method based on the Company's percentage ownership of current production. Each working interest owner in a well generally has the right to a specific percentage of production, although actual production sold may differ from an owner's ownership percentage. Under entitlement accounting, a receivable is recorded when underproduction occurs and a payable when overproduction occurs. Gains and losses associated with the sale of in place natural gas and crude oil reserves and related assets are classified as net operating revenues in the consolidated statements of income and comprehensive income based on the Company's strategy of continuing such sales in order to maximize the economic value of its assets. Accounting for Price Risk Management. The Company engages in price risk management activities from time to time primarily for non-trading and to a lesser extent for trading purposes. Derivative financial instruments (primarily price swaps and costless collars) are utilized for non-trading purposes to hedge the impact of market fluctuations on natural gas and crude oil market prices. Hedge accounting is utilized in non-trading activities when there is a high degree of correlation between price movements in the derivative and the item designated as being hedged. Gains and losses on derivative financial instruments used for hedging purposes are recognized as revenue in the same period as the hedged item. Gains and losses on hedging instruments that are closed prior to maturity are deferred in the consolidated balance sheets. In instances where the anticipated correlation of price movements does not occur, hedge accounting is terminated and future changes in the value of the derivative are recognized as gains or losses using the mark-to-market method of accounting. Derivative and other financial instruments utilized in connection with trading activities, primarily price swaps and call options, are accounted for using the mark-to-market method, under which changes in the market value of outstanding financial instruments are recognized as gains or losses in the period of change. The cash flow impact of derivative and other financial instruments used for non-trading and trading purposes is reflected as cash flows from operating activities in the consolidated statements of cash flows. Capitalized Interest Costs. Certain interest costs have been capitalized as a part of the historical cost of unproved oil and gas properties and in work in progress for exploratory drilling and related facilities with significant cash outlays. Interest costs capitalized during each of the three years in the period ended December 31, 1998 are set out in the consolidated statements of income and comprehensive income. Income Taxes. The Company accounts for income taxes under the provisions of SFAS No. 109 - "Accounting for Income Taxes". SFAS No. 109 requires the asset and liability approach for accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases (See Note 8 "Income Taxes"). Foreign Currency Translation. For subsidiaries whose functional currency is deemed to be other than the U.S. dollar, asset and liability accounts are translated at year-end exchange rates and revenue and expenses are translated at average exchange rates prevailing during the year. Translation adjustments are included as a separate component of shareholders' equity. Any gains or losses on transactions or monetary assets or liabilities in currencies other than the functional currency are included in net income in the current period. Net Income Per Share. In accordance with the provisions of SFAS No. 128 - "Earnings per Share", basic net income per share is computed on the basis of the weighted-average number of common shares outstanding during the periods. Diluted net income per share is computed based upon the weighted-average number of common shares plus the assumed issuance of common shares for all potentially dilutive securities. (See Note 10 "Net Income Per Share" for additional information to reconcile the difference between the Average Number of Common Shares outstanding for basic and diluted net income per share). F-9
47 2. NATURAL GAS AND CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS NET OPERATING REVENUES Natural gas revenues, trade for 1998, 1997 and 1996 are net of costs of natural gas purchased for sale related to natural gas marketing activities of $44.8 million, $73.6 million and $72.6 million, respectively. Natural gas revenues, associated for 1998, 1997 and 1996 are net of costs of natural gas purchased for sale related to natural gas marketing activities of $51.0 million, $47.7 million and $24.9 million, respectively. In March 1995, in a series of transactions with Enron Corp. and an affiliate of Enron Corp., the Company exchanged all of its fuel supply and purchase contracts and related price swap agreements associated with a Texas City cogeneration plant (the "Cogen Contracts") for certain natural gas price swap agreements of equivalent value issued by the affiliate that are designated as hedges (the "Swap Agreements"). Such Swap Agreements were closed on March 31, 1995. As a result of the transactions, the Company was relieved of all performance obligations associated with the Cogen Contracts. The Company will realize net operating revenues and receive corresponding cash payments of approximately $91 million during the period extending through December 31, 1999, under the terms of the closed Swap Agreements. The estimated fair value of the Swap Agreements was approximately $81 million at the date the Swap Agreements were received in exchange for the Cogen Contracts. The net effect of this series of transactions resulted in increases in net operating revenues and cash receipts for the Company during 1995 and 1996 of approximately $13 million and $7 million, respectively, with offsetting decreases in 1998 and 1999 versus that anticipated under the Cogen Contracts. The total cash payments receivable under the terms of the Swap Agreements were approximately $4 million and $13 million at December 31, 1998 and 1997, respectively, and are presented in the accompanying balance sheet as Accounts Receivable - Associated Companies for the $4 million and $9 million current portion, respectively, and as Other Assets for the $4 million noncurrent portion at December 31, 1997. The corresponding total future revenue of approximately $4 million and $13 million, respectively, is classified as Deferred Revenue. (See Note 14 "Price and Interest Rate Risk Management"). 3. OTHER ASSETS In December 1997, the Company and Enron Corp. entered into an Equity Participation and Business Opportunity Agreement (the "Business Opportunity Agreement"). (See Note 7 "Transactions with Enron Corp. and Related Parties - Business Opportunity Agreement"). Among other things, under the agreement, Enron Corp. granted to the Company ten-year options to purchase 3,200,000 shares of Enron Corp. common stock at a price of $39.1875 per share which was the closing price of the stock on the date that the agreement was approved by the Board of Directors of the Company. The option vesting schedule provides that 25% vested immediately, 15% vest on the anniversary of the Business Opportunity Agreement in 1998 and 10% vest each anniversary thereafter until all of the options are vested. Vesting will be accelerated in the event of a change of control of the Company. For such purposes, a "change of control" means that (a) Enron Corp. no longer owns capital stock of the Company representing at least 35% of the voting power for the election of directors and (b) a majority of the members of the Board of Directors of the Company consists of persons who are not officers or directors of Enron Corp. or any affiliate of Enron Corp. other than the Company. Other Assets at December 31, 1998 and 1997 includes $23.3 million or $7.29 per share representing the estimated fair value of the Enron Corp. stock options at the date of grant. Such estimated fair value was determined using the Black-Scholes option-pricing model with the following weighted-average assumptions at the date the options were issued: (1) dividend yield of 2.5%, (2) expected volatility of 17.5%, (3) risk-free interest rate of 5.85%, and (4) expected average life of 4.0 years. Receipt of the options represented a capital contribution from Enron Corp. and, accordingly, the fair value received, net of tax effects of $8.2 million, was credited to Additional Paid In Capital. (See Note 16 "New Accounting Pronouncement - SFAS No. 133"). F-10
48 4. LONG-TERM DEBT Long-Term Debt at December 31 consisted of the following: <TABLE> <CAPTION> 1998 1997 ---------- -------- <S> <C> <C> Commercial Paper............................................ $ 162,539 $ 42,415 6.50% Notes due 2004........................................ 100,000 100,000 6.70% Notes due 2006........................................ 150,000 150,000 6.50% Notes due 2007........................................ 100,000 100,000 6.00% Notes due 2008........................................ 175,000 - 6.65% Notes due 2028........................................ 150,000 - 9.10% Notes due 1998........................................ - 20,000 Subsidiary Debt due 2001.................................... 105,000 105,000 Subsidiary Debt due 1998.................................... - 31,000 Other....................................................... 240 360 ---------- -------- 942,779 548,775 Affiliate................................................... 200,000 192,500 ---------- -------- Total............................................. $1,142,779 $741,275 ========== ======== </TABLE> The Company has three credit facilities with domestic and foreign banks which provide for an aggregate of $550 million in long-term committed credit, with $250 million expiring in 1999 and $300 million expiring in 2002. With respect to the aggregate $250 million from two separate facilities, both of which expire during 1999, the Company may, at its option, extend the final maturity date of any advances made under the facilities by one full year from the expiration date of the applicable facility, effectively qualifying such debt as long-term. Advances under all three agreements bear interest, at the option of the Company, based upon a base rate or a Eurodollar rate. At December 31, 1998, there were no advances outstanding under any of these agreements. Commercial Paper and short-term funding from uncommitted credit facilities provide financing for various corporate purposes and bear interest based upon market rates. No advances were outstanding under the uncommitted lines on December 31, 1998 or 1997. Commercial paper, uncommitted credit and affiliate facility balances (when present) are classified as long-term debt based on the Company's intent and ability to ultimately replace such amounts with other long-term debt. (See Note 14 "Price and Interest Rate Risk Management"). The 6.00% to 6.70% Notes due 2004 to 2028 were issued through public offerings and have effective interest rates of 6.14% to 6.83%. The Subsidiary Debt due 2001 bears interest at variable market-based rates and is guaranteed by the Company. Certain borrowings of the Company contain covenants requiring the maintenance of certain financial ratios and limitations on liens, debt issuance and dispositions of assets. These covenants include a 50% debt-to- total-capital limitation. Should commodity price levels experienced in late 1998 and early 1999 persist, the resulting reduction in cash flow available from operations may necessitate further action(s) which could include a reduction in capital expenditure plans, the issuance of preferred stock and/or common equity, and/or the renegotiation of the debt covenants in order to remain in compliance. At December 31, 1998, the aggregate annual maturities of long-term debt outstanding were less than $1.0 million for each of the years 1999 and 2000, $105 million for 2001 and none for 2002 and 2003. Shelf Registration. The Company may sell from time to time up to an aggregate of approximately $90 million in debt securities and/or common stock pursuant to an effective "shelf" registration statement filed with the Securities and Exchange Commission. Financing Arrangements With Enron Corp. The Company engages in various transactions with Enron Corp. that are characteristic of a consolidated group under common control. Accordingly, the Company maintains reciprocal agreements with Enron Corp. that provide for the borrowing by the Company of up to F-11
49 $200 million and investing by the Company of surplus funds of up to $200 million at market-based interest rates through December 31, 1999. Advances from Enron Corp. of $200 million and $193 million were outstanding at December 31, 1998 and 1997, respectively, and such balances were classified as long-term based on the Company's intent and ability to ultimately replace such amounts with other long-term debt. There were no investments with Enron Corp. at December 31, 1998 or 1997. (See Note 14 "Price and Interest Rate Risk Management"). Fair Value Of Long-Term Debt. At December 31, 1998 and 1997, the Company had $1,143 million and $741 million, respectively, of long-term debt which had fair values of approximately $1,141 million and $744 million, respectively. The fair value of long-term debt is the value the Company would have to pay to retire the debt, including any premium or discount to the debtholder for the differential between the stated interest rate and the year-end market rate. The fair value of long-term debt is based upon quoted market prices and, where such quotes were not available, upon interest rates available to the Company at year-end. 5. VOLUMETRIC PRODUCTION PAYMENT In September 1992, the Company sold a volumetric production payment for $326.8 million to a limited partnership. Under the terms of the production payment, as amended October 1, 1993, the Company conveyed a real property interest of certain natural gas and other hydrocarbons to the purchaser. Deliveries were scheduled at the rate of 50 billion British thermal units per day through March 31, 1999. The Company accounted for the proceeds received in the transaction as deferred revenue, which was amortized into revenue and income as natural gas and other hydrocarbons were produced and delivered during the term of the volumetric production payment agreement. In December 1998, the Company settled the remainder of the contract in cash which was not materially different from the recorded deferred revenue, and delivery obligations were terminated. 6. SHAREHOLDERS' EQUITY The Board of Directors of the Company has approved an authorization for purchasing and holding in treasury at any time up to 1,000,000 shares of common stock of the Company for the purpose of, but not limited to, meeting obligations associated with the exercise of stock options granted to qualified employees pursuant to the Company's stock option plans. The Board of Directors has also approved the selling from time to time, subject to certain conditions, of put options on the common stock of the Company. The 1,000,000 share limit mentioned above applies to shares held in treasury and unexpired put options outstanding. In February 1997, as amended in February 1998, the Board of Directors authorized the additional purchase of up to an aggregate maximum of 10 million shares of common stock of the Company from time to time in the open market to be held in treasury for the purpose of, but not limited to, fulfilling any obligations arising under the Company's stock option plans and any other approved transactions or activities for which such common stock shall be required. At December 31, 1998 and 1997, 6,276,156 shares and 4,935,744 shares, respectively, were held in treasury under these authorizations. (See Note 9 "Commitments and Contingencies - Treasury Shares"). The Company has, from time to time, entered into transactions in which it writes put options on its own common stock. At December 31, 1998, there were put options outstanding for 175,000 shares of common stock. Such options have strike prices ranging from $13.13 to $21.13 per share and are exercisable by the counterparties only on the dates of expiration ranging from May 1999 to December 1999. Settlement alternatives are at the option of the Company and include physical share, net share and net cash settlement. These transactions are accounted for as equity transactions with any premiums received and cash payments made being recorded to Additional Paid In Capital in the consolidated balance sheets. 7. TRANSACTIONS WITH ENRON CORP. AND RELATED PARTIES Business Opportunity Agreement. In December 1997, Enron Corp. and the Company entered into the Business Opportunity Agreement which defines certain obligations that Enron Corp. owes to the Company and relieves Enron Corp. from certain obligations to the Company that it might otherwise have, including the obligation to offer certain business opportunities to the Company. Enron Corp. has advised the Company that, F-12
50 although it believes that it has conducted its business in a manner that is consistent with its duties as a majority shareholder of the Company, it was motivated to enter into the Business Opportunity Agreement because of the difficulty of determining the applicability of the law relating to duties that Enron Corp. may owe to the Company in connection with Enron Corp.'s finance and trading business and because of Enron Corp.'s desire to have more flexibility in pursuing business opportunities identified by or developed solely by Enron Corp. personnel. The Business Opportunity Agreement was approved by the Board of Directors of the Company after it was approved unanimously by a special committee of the Board of Directors consisting of the Company's independent directors. The Business Opportunity Agreement provides generally that, so long as such activities are conducted in compliance with the Business Opportunity Agreement in all material respects, Enron Corp. may pursue business opportunities independently of the Company. The Business Opportunity Agreement contains an acknowledgment by the Company that Enron Corp.'s finance and trading business may result in the acquisition by Enron Corp. of oil and gas properties or companies and that in certain cases Enron Corp. or entities in which Enron Corp. has an interest may acquire such assets pursuant to bidding or auction processes in which the Company is also a bidder. In the Business Opportunity Agreement, the Company acknowledges and agrees that such activities may have an impact on the Company or the price it pays for properties or securities it purchases from others. The Business Opportunity Agreement contains an acknowledgement and agreement by the Company that, to the extent that a court might hold that the conduct of such activity is a breach of a duty to the Company (and without admitting that the conduct of such activity is such a breach of duty), the Company waives any and all claims and courses of action that it may have to claim the conduct of such activity is a breach of duty to the Company. The Business Opportunity Agreement contains certain restrictions on the conduct of Enron's business. It also provides that, except with respect to business opportunities pursued jointly by Enron Corp. and the Company and except as otherwise agreed to between Enron Corp. and the Company, Enron Corp.'s business will be conducted through the use of its own personnel and assets and not with the use of any personnel or assets of the Company. The Business Opportunity Agreement states that its provisions relate exclusively to the duties that Enron Corp. owes the Company and that nothing in the Business Opportunity Agreement affects the fiduciary or other duties owed to the Company by any individual director or officer of the Company in his or her capacity as such. In this connection, Enron Corp. has agreed that its representatives on the Board of Directors of the Company will not, for the purpose of enabling Enron Corp. to pursue an opportunity in the oil and gas business, vote in such a manner as to effectively prevent, prohibit or restrict the Company from pursuing such opportunity. In consideration for the Company's agreements in the Business Opportunity Agreement, Enron Corp. provided valuable consideration to the Company, including options to purchase common stock of Enron Corp. that will give the Company the opportunity to participate in future appreciation in value of Enron, including any appreciation in value resulting from activities that the Company has agreed to permit Enron Corp. and its subsidiaries to pursue. (See Note 3 "Other Assets"). The Business Opportunity Agreement also included (i) an agreement to replace the existing services agreement, under which Enron Corp. provides certain services to the Company, with a new services agreement under which the Company's maximum payments to Enron Corp. for allocated indirect costs will be reduced by $2.8 million per year, (ii) an agreement by Enron Corp. relieving the Company of the obligation to bear the costs of any registration of sales by Enron Corp. of shares of common stock of the Company, (iii) an agreement by Enron Corp. to pay the costs of registration of the Company's sales of Enron Corp. common stock acquired upon exercise of the options granted in the Business Opportunity Agreement, (iv) an agreement that if Enron Corp. takes any action that results in the loss by the Company of its status as an "independent producer" under the Internal Revenue Code, Enron Corp. will pay the Company each year through 2006 the lesser of (a) $1 million and (b) an amount which, after payment of applicable taxes, will compensate the Company for the additional income tax liability resulting from the loss of independent producer status, (v) and an agreement that if Enron Corp. requests that the Company relocate its offices, and if the Company agrees to do so, Enron will pay the Company's moving expenses, including expenses of building out or refurbishing the space in its new offices and expenses of removing and reinstalling the Company's telecommunications and information systems facilities. In addition, F-13
51 pursuant to the Business Opportunity Agreement, Enron Corp. agreed to cause its subsidiary, Houston Pipe Line Company, to enter into various agreements with the Company rearranging certain existing contractual arrangements between them and Enron Corp., and the Company entered into a licensing agreement covering the Enron Corp. name and mark and recognizing that the EOG and EOGI names and marks belong to the Company. In the Business Opportunity Agreement, Enron Corp. and the Company also entered into agreements in principle regarding the manner in which they will share the burdens and benefits of the integrated projects under joint development by Enron Corp. and the Company in Qatar, Mozambique and Uzbekistan. The agreements in principle provide generally that the Company's interests in these projects will be 20%, 20% and 80%, respectively, of the combined ownership interest of the Company and Enron Corp. In December 1998, the Company sold its interest in the Uzbekistan project and anticipates disposing of its interest in the Qatar project in early 1999. The Business Opportunity Agreement also contains provisions that give Enron Corp. the right to maintain its equity interest in the Company at certain levels. It provides that if the Company issues additional shares of its capital stock, Enron Corp. will have the right to purchase additional shares of capital stock of the Company as follows: (i) if Enron Corp. owns a majority interest, Enron Corp. will have the right to purchase sufficient shares to permit it to retain its majority interest; (ii) if Enron Corp. does not own a majority interest but accounts for the assets and operations of the Company on a consolidated basis for financial reporting purposes Enron Corp. will have the right to purchase sufficient shares to permit it to continue to account for the Company on a consolidated basis; and (iii) if Enron Corp. accounts for the assets and operations of the Company using the equity method for financial reporting purposes Enron Corp. will have the right to purchase sufficient shares to permit it to continue to account for the Company using the equity method. Any such purchase by Enron Corp. will be for cash at 97% of the average closing price per share over a specified 20 day period (reflecting a 3% private placement discount). Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues. Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues include revenues from and associated costs paid to various subsidiaries and affiliates of Enron Corp. pursuant to contracts which, in the opinion of management, are no less favorable than could be obtained from third parties. (See Note 2 "Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues"). Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues also include certain commodity price swap and NYMEX-related commodity transactions with Enron Corp. affiliated companies, which in the opinion of management, are no less favorable than could be received from third parties. (See Note 14 "Price and Interest Rate Risk Management.) General and Administrative Expenses. The Company is charged by Enron Corp. for all direct costs associated with its operations. Such direct charges, excluding benefit plan charges (See Note 9 "Commitments and Contingencies - Employee Benefit Plans"), totaled $14.2 million, $16.1 million and $17.0 million for the years ended December 31, 1998, 1997 and 1996, respectively. Management believes that these charges are reasonable. Additionally, certain administrative costs not directly charged to any Enron Corp. operations or business segments are allocated to the entities of the consolidated group. Allocation percentages are generally determined utilizing weighted average factors derived from property gross book value, net operating revenues and payroll costs. Effective January 1, 1997, the Company entered into an agreement with Enron Corp. with an initial term of ten years through December 2006, which agreement replaced a similar previous agreement, providing for services substantially identical in nature and quality to those services previously provided and for allocated indirect costs incurred in rendering such services up to a maximum of approximately $5.1 million for 1998 and $5.3 million for 1997. Maximum allocated indirect costs under the previous service agreement were $7.5 million for 1996. The limit on cost for the allocated indirect services provided by Enron Corp. to the Company will increase in subsequent years for inflation and certain changes in the Company's allocation bases. Management believes the indirect allocated charges for the numerous types of support services provided by the corporate staff are reasonable. Approximately $5.1 million and $5.3 million was incurred by the Company for indirect general and administrative expenses for 1998 and 1997, respectively. Under the previous F-14
52 agreement, approximately $7.5 million was charged to the Company for indirect general and administrative expenses for 1996. Financing. See Note 4 "Long-Term Debt - Financing Arrangements with Enron Corp." for a discussion of financing arrangements with Enron Corp. Enron Corp. Ownership. In December 1998, Enron Corp. publicly disclosed that it had received an unsolicited indication of interest from a third party with respect to exploring a possible transaction pursuant to which the third party would acquire Enron Corp.'s shares of common stock of the Company, and offer to acquire the remaining shares of outstanding common stock of the Company. In response to this indication of interest, the Board of Directors of the Company has established a special committee consisting of two independent directors who have retained a financial advisor and legal counsel. Although Enron Corp. has publicly indicated that it currently intends to actively explore alternative transactions for its Company common stock along with the unsolicited indication of interest, there can be no assurance that any such transactions will be pursued or, if pursued, will be consummated. 8. INCOME TAXES The principal components of the Company's net deferred income tax liability at December 31, 1998 and 1997 were as follows: <TABLE> <CAPTION> 1998 1997 -------- -------- <S> <C> <C> Deferred Income Tax Assets Cogen Contract Exchange.......................... $ 9,519 $ 19,781 Net Operating Loss Carryforward, India........... 44,640 27,500 Non-Producing Leasehold Costs.................... 19,411 13,391 Seismic Costs Capitalized for Tax................ 7,687 7,144 Alternative Minimum Tax Credit Carryforward...... 17,656 12,681 Trading Activity................................. 4,253 - Other............................................ 12,084 11,441 -------- -------- Total Deferred Income Tax Assets......... 115,250 91,938 Deferred Income Tax Liabilities Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization.................... 360,045 304,122 Capitalized Interest............................. 12,512 10,231 Volumetric Production Payment Book Revenue Over Income for Tax................................ - 58,850 Trading Activity................................. - 3,470 Other............................................ 3,030 2,943 -------- -------- Total Deferred Income Tax Liabilities.... 375,587 379,616 -------- -------- Net Deferred Income Tax Liability........ $260,337 $287,678 ======== ======== </TABLE> The components of income (loss) before income taxes were as follows: <TABLE> <CAPTION> 1998 1997 1996 -------- -------- -------- <S> <C> <C> <C> United States...................................... $ (3,297) $103,831 $146,335 Foreign............................................ 63,579 59,639 44,627 -------- -------- -------- Total.................................... $ 60,282 $163,470 $190,962 ======== ======== ======== </TABLE> F-15
53 Total income tax provision (benefit) was as follows: <TABLE> <CAPTION> 1998 1997 1996 -------- -------- -------- <S> <C> <C> <C> Current: Federal.......................................... $ 10,496 $ 50,494 $ 21,064 State............................................ 1,474 840 (916) Foreign.......................................... 18,935 23,614 28,530 -------- -------- -------- Total.................................... 30,905 74,948 48,678 Deferred: Federal.......................................... (31,279) (32,711) 13,620 State............................................ (4,589) 348 (1,826) Foreign.......................................... 9,074 (1,085) (9,518) -------- -------- -------- Total.................................... (26,794) (33,448) 2,276 -------- -------- -------- Income Tax Provision............................... $ 4,111 $ 41,500 $ 50,954 ======== ======== ======== </TABLE> The differences between taxes computed at the U.S. federal statutory tax rate and the Company's effective rate were as follows: <TABLE> <CAPTION> 1998 1997 1996 -------- -------- -------- <S> <C> <C> <C> Statutory Federal Income Tax Rate.................. 35.00% 35.00% 35.00% State Income Tax, Net of Federal Benefit........... (3.36) 0.47 (0.76) Income Tax Related to Foreign Operations........... 4.76 2.83 6.16 Tight Gas Sand Federal Income Tax Credits.......... (17.36) (7.51) (8.22) Revision of Prior Years' Tax Estimates............. (10.78) (4.34) (4.46) Other.............................................. (1.45) (1.06) (1.04) -------- -------- -------- Effective Income Tax Rate................ 6.81% 25.39% 26.68% ======== ======== ======== </TABLE> In 1997, the Company and Enron Corp. agreed to replace an existing tax allocation agreement with a new tax allocation agreement. In the new agreement, Enron Corp. agreed to refund a $13 million payment made by the Company pursuant to the existing agreement, the Company agreed to release Enron Corp. from the liabilities assumed related to the $13 million payment and the parties agreed to indemnify each other in a manner consistent with a former agreement. Enron Corp. also advanced the Company approximately $50 million to fund certain federal income taxes related to the 1995 taxable year. This advance is being repaid in annual installments through January 1, 2001. The Company's foreign subsidiaries' undistributed earnings of approximately $243 million at December 31, 1998 are considered to be indefinitely invested outside the U.S. and, accordingly, no U.S. federal or state income taxes have been provided thereon. Upon distribution of those earnings in the form of dividends, the Company may be subject to both foreign withholding taxes and U.S. income taxes, net of allowable foreign tax credits. Determination of any potential amount of unrecognized deferred income tax liabilities is not practicable. The Company has a $93 million India tax net operating loss carryforward at December 31, 1998. The loss carryforward utilization is limited to future taxable earnings of Enron Oil & Gas India Ltd. which earnings are expected to exceed this carryforward amount before the carryforward period expires. The India carryforward period is eight years, and unutilized net operating loss carryforward will begin to expire with the fiscal year ending March 31, 2002. The Company has an alternative minimum tax ("AMT") credit carryforward of $18 million which can be used to offset regular income taxes payable in future years. The AMT credit carryforward has an indefinite carryforward period. F-16
54 9. COMMITMENTS AND CONTINGENCIES Employee Benefit Plans. Employees of the Company are covered by various retirement, stock purchase and other benefit plans of Enron Corp. During each of the years ended December 31, 1998, 1997 and 1996, the Company was charged $6.4 million, $5.0 million and $5.0 million, respectively, for all such benefits, including pension expense totaling $1.3 million, $1.0 million and $1.0 million, respectively, by Enron Corp. As of September 30, 1998, the most recent valuation date of the various Enron Corp. pension and other postretirement plans in which the employees of the Company participate, the actuarial present value of projected aggregate plan benefit obligations exceeded the aggregate plan net assets by approximately $24 million. The assumed discount rate, rate of return on plan assets and rate of increases in wages used in determining the actuarial present value of projected plan benefits were 6.75%, 10.5% and 4.0%, respectively. The Company also has in effect pension and savings plans related to its Canadian, Trinidadian and Indian subsidiaries. Activity related to these plans is not material relative to the Company's operations. The Company provides certain postretirement medical and dental benefits to eligible employees and their eligible dependents. Benefits are provided under the provisions of contributory defined dollar benefit plans of Enron Corp. The Company accrues the cost of these postretirement benefits over the service lives of the employees expected to be eligible to receive such benefits. The transition obligation is being amortized over an average period of 19 years. Stock Plans Stock Options. The Company has various stock plans ("the Plans") under which employees of the Company and its subsidiaries and nonemployee members of the Board of Directors have been or may be granted rights to purchase shares of common stock of the Company at a price not less than the market price of the stock at the date of grant. Stock options granted under the Plans vest over a period of time based on the nature of the grants and as defined in the individual grant agreements. Terms for stock options granted under the Plans have not exceeded a maximum term of 10 years. The Company accounts for the stock options under the provisions and related interpretations of Accounting Principles Board Opinion No. 25 ("APB No. 25") - "Accounting for Stock Issued to Employees." No compensation expense is recognized for such options. In accordance with SFAS No. 123 - "Accounting for Stock-Based Compensation" issued in 1995, the Company has continued to apply APB No. 25 for purposes of determining net income and to present the pro forma disclosures required by SFAS No. 123. The following table sets forth the option transactions under the Plans for the years ended December 31 (options in thousands): <TABLE> <CAPTION> 1998 1997 1996 ----------------- ----------------- ----------------- AVERAGE AVERAGE AVERAGE GRANT GRANT GRANT OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE ------- ------- ------- ------- ------- ------- <S> <C> <C> <C> <C> <C> <C> Outstanding at January 1....... 9,735 $19.99 8,796 $20.70 8,019 $18.61 Granted...................... 5,949 15.76 3,079 20.18 2,941 24.53 Exercised.................... (172) 15.14 (261) 17.16 (1,989) 17.95 Forfeited.................... (476) 20.62 (1,879) 24.06 (175) 20.28 ------- ------- ------- Outstanding at December 31..... 15,036 18.35 9,735 19.99 8,796 20.70 ======= ======= ======= Options Exercisable at December 31........................... 7,703 19.38 5,618 19.70 4,402 19.13 ======= ======= ======= Options Available for Future Grant........................ 3,098 2,519 3,741 ======= ======= ======= Average Fair Value of Options Granted During Year.......... $ 4.75 $ 6.96 $ 9.29 ======= ======= ======= </TABLE> F-17
55 The fair value of each option grant is estimated using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants in 1998, 1997 and 1996, respectively: (1) dividend yield of 0.6%, 0.6% and 0.5%, (2) expected volatility of 26%, 27% and 31%, (3) risk-free interest rate of 5.1%, 6.3% and 5.8%, and (4) expected life of 4.9 years, 5.2 years and 5.5 years. During 1997, in response to extremely competitive conditions for technical personnel, the Company cancelled options issued in 1996 to purchase 1,282,000 shares of common stock at an exercise price of $25.38 per share, and reissued the same number of options with an exercise price of $18.25 per share. The reissue did not involve any executive officers of the Company. The following table summarizes certain information for the options outstanding at December 31, 1998 (options in thousands): <TABLE> <CAPTION> OPTIONS OUTSTANDING OPTIONS EXERCISABLE ------------------------------ -------------------- WEIGHTED WEIGHTED WEIGHTED AVERAGE AVERAGE AVERAGE REMAINING GRANT GRANT RANGE OF GRANT PRICES OPTIONS LIFE PRICE OPTIONS PRICE - --------------------- ------- --------- -------- -------- --------- <S> <C> <C> <C> <C> <C> $ 9.00 to $12.99...................... 409 3 years $ 9.87 409 $ 9.87 13.00 to 17.99...................... 5,607 9 14.98 1,737 16.08 18.00 to 22.99...................... 7,410 6 20.18 4,494 20.51 23.00 to 29.00...................... 1,610 6 23.81 1,063 23.77 ------ ----- 9.00 to 29.00...................... 15,036 7 18.35 7,703 19.38 ====== ===== </TABLE> The Company's pro forma net income and net income per share of common stock for 1998, 1997 and 1996, had compensation costs been recorded in accordance with SFAS No. 123, are presented below (in millions except per share data): <TABLE> <CAPTION> 1998 1997 1996 -------------------- -------------------- -------------------- AS AS AS REPORTED PRO FORMA REPORTED PRO FORMA REPORTED PRO FORMA -------- --------- -------- --------- -------- --------- <S> <C> <C> <C> <C> <C> <C> Net Income................ $56.2 $47.3 $122.0 $116.7 $140.0 $135.5 Net Income per Share of Common Stock Basic................ $ .36 $ .31 $ .78 $ .74 $ .88 $ .85 ===== ===== ====== ====== ====== ====== Diluted.............. $ .36 $ .30 $ .77 $ .74 $ .87 $ .84 ===== ===== ====== ====== ====== ====== </TABLE> The effects of applying SFAS No. 123 in this pro forma disclosure should not be interpreted as being indicative of future effects. SFAS No. 123 does not apply to awards prior to 1995, and the extent and timing of additional future awards cannot be predicted. The Black-Scholes model used by the Company to calculate option values, as well as other currently accepted option valuation models, were developed to estimate the fair value of freely tradable, fully transferable options without vesting and/or trading restrictions, which significantly differ from the Company's stock option awards. These models also require highly subjective assumptions, including future stock price volatility and expected time until exercise, which significantly affect the calculated values. Accordingly, management does not believe that this model provides a reliable single measure of the fair value of the Company's stock option awards. Restricted Stock. Under the Plans, participants may be granted restricted stock without cost to the participant. The shares granted vest to the participant at various times ranging from one to seven years. Upon F-18
56 vesting, the shares are released to the participants. The following summarizes shares of restricted stock granted: <TABLE> <CAPTION> RESTRICTED SHARES ------------------------------ 1998 1997 1996 -------- -------- -------- <S> <C> <C> <C> Outstanding at January 1............................. 284,000 284,000 - Granted............................................ 108,500 - 301,500 Released to Participants........................... (14,166) - (17,500) Forfeited or Expired............................... (33,000) - - -------- -------- -------- Outstanding at December 31........................... 345,334 284,000 284,000 ======== ======== ======== Average Fair Value of Shares Granted During Year..... $ 20.11 $ - $ 23.50 ======== ======== ======== </TABLE> The fair value of the restricted shares at date of grant has been recorded in shareholders' equity as unearned compensation and is being amortized as compensation expense. Related compensation expense for 1998, 1997 and 1996 was approximately $1.5 million, $1.0 million and $1.4 million, respectively. Treasury Shares. During 1998, 1997 and 1996, the Company purchased or was tendered 1,590,200, 4,954,344 and 2,383,727 of its common shares, respectively, and delivered such shares upon the exercise of stock options and awards of restricted stock, except for shares held in treasury at December 31, 1998, 1997 and 1996. The difference between the cost of the treasury shares and the exercise price of the options, net of federal income tax benefit of $.3 million, $.5 million and $6.1 million for the years 1998, 1997 and 1996, respectively, is reflected as an adjustment to Additional Paid In Capital. In December 1992, as amended in September 1994 and December 1996, the Company commenced a stock repurchase program of up to 1,000,000 shares authorized by the Board of Directors to facilitate the availability of treasury shares of common stock for, but not limited to, the settlement of employee stock option exercises pursuant to the Plans. In February 1997 as amended in February 1998, the Board of Directors authorized the additional purchase of up to 10 million shares for similar purposes. At December 31, 1998 and 1997, 6,276,156 and 4,935,744 shares, respectively, were held in treasury under these authorizations. (See Note 6 "Shareholders' Equity"). Letters Of Credit. At December 31, 1998 and 1997, the Company had letters of credit outstanding totaling approximately $127 million and $169 million, respectively. Contingencies. Enron Oil & Gas India Ltd. ("EOGIL"), a wholly-owned subsidiary of the Company, is a respondent in two public interest lawsuits filed in the Delhi High Court, India. The first (the "Wadehra Action") was brought by B. L. Wadehra, an Indian public interest lawyer, against the Union of India, EOGIL, EOGIL co-participants in the Panna and Mukta fields, Reliance Industries Limited ("Reliance") and Oil & Natural Gas Corporation Limited ("ONGC"), and certain other respondents. ONGC is the Indian national oil company and is wholly-owned by the Union of India. The second suit (the "CPIL Action") was brought by the Centre for Public Interest Litigation and the National Alliance of People's Movement against the Union of India, the Central Bureau of Investigation, ONGC, Reliance and EOGIL. Petitioners in both the Wadehra Action and the CPIL Action allege various improprieties in the award of the Panna and Mukta fields to EOGIL, Reliance and ONGC, and seek the cancellation of the Production Sharing Contract for the Panna and Mukta fields. The Union of India is vigorously disputing these allegations. The Company believes that the public competitive bidding process for the fields was fair and that the award of these fields to EOGIL, Reliance and ONGC was proper. Following a series of hearings, the Delhi High Court has entered an order dismissing both lawsuits. The plaintiffs have filed a special leave petition seeking to appeal this decision to the India Supreme Court. Although no assurances can be given, based on currently available information the Company believes that the ultimate resolution of these matters will not have a material adverse effect on its financial condition or results of operations. There are various other suits and claims against the Company that have arisen in the ordinary course of business. However, management does not believe these suits and claims will individually or in the aggregate have a material adverse effect on the Company's financial condition or results of operations. The Company has been named as a potentially responsible party in certain Comprehensive Environmental Response Compensation and Liability Act proceedings. However, management does not F-19
57 believe that any potential assessments resulting from such proceedings will individually or in the aggregate have a materially adverse effect on the financial condition or results of operations of the Company. 10. NET INCOME PER SHARE The difference between the Average Number of Common Shares outstanding for basic and diluted net income per share of common stock is due to the assumed issuance of approximately 709,000, 784,000 and 1,672,000 common shares relating to employee stock options in 1998, 1997 and 1996, respectively. 11. CASH FLOW INFORMATION Cash paid for interest and income taxes was as follows for the years ended December 31: <TABLE> <CAPTION> 1998 1997 1996 ------- ------- ------- <S> <C> <C> <C> Interest (net of amount capitalized).................... $51,166 $27,759 $14,237 Income taxes............................................ 38,551 28,708 42,014 </TABLE> 12. BUSINESS SEGMENT INFORMATION The Company's operations are all natural gas and crude oil exploration and production related. The Company adopted SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," during the fourth quarter of 1998. SFAS No. 131 establishes standards for reporting information about operating segments in annual financial statements and requires selected information about operating segments in interim financial reports. Operating segments are defined as components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker, or decision making group, in deciding how to allocate resources and in assessing performance. The Company's chief operating decision making group is the Executive Committee, which consists of the President and Chief Executive Officer and other key officers. This group routinely reviews and makes operating decisions related to significant issues associated with each of the Company's major producing areas in the United States and each significant international location. For segment reporting purposes, the major U.S. producing areas have been aggregated as one reportable segment due to similarities in their operations as allowed by SFAS No. 131. Financial information by reportable segment is presented below for the years ended December 31, or at December 31: <TABLE> <CAPTION> UNITED STATES CANADA TRINIDAD INDIA OTHER TOTAL ------------- -------- -------- -------- -------- ---------- <S> <C> <C> <C> <C> <C> <C> 1998 Net Operating Revenues............. $ 564,378 $ 68,622 $ 66,967 $ 72,826 $ (3,605) $ 769,188 Depreciation, Depletion and Amortization..................... 265,738 25,972 12,867 8,456 2,073 315,106 Operating Income (Loss)............ 54,272 11,908 42,094 41,718 (36,331) 113,661 Interest Income.................... 216 88 507 205 131 1,147 Other Income (Expense)............. (559) - (150) (1,761) (3,477) (5,947) Interest Expense................... 53,773 6,558 859 100 - 61,290 Income Tax Provision (Benefit)..... (6,214) (1,112) 21,517 13,401 (23,481) 4,111 Additions to Oil and Gas Properties....................... 547,209 49,142 19,347 46,657 27,997 690,352 Total Assets....................... 2,238,969 277,861 131,964 289,596 79,705 3,018,095 1997 Net Operating Revenues............. $ 603,845 $ 73,466 $ 66,000 $ 35,332 $ 4,858 $ 783,501 Depreciation, Depletion and Amortization..................... 239,418 23,116 11,031 3,716 898 278,179 Operating Income (Loss)............ 138,213 19,983 38,968 13,794 (18,183) 192,775 Interest Income.................... 2,746 392 484 134 366 4,122 Other Income (Expense)............. (5,517) 4 (289) (848) 940 (5,710) Interest Expense................... 28,548 8,132 4,701 42 - 41,423 Income Tax Provision (Benefit)..... 30,940 (3,228) 21,538 1,402 (9,152) 41,500 Additions to Oil and Gas Properties....................... 468,168 79,789 163 67,777 10,301 626,198 Total Assets....................... 2,036,933 276,998 116,578 252,115 40,731 2,723,355 (Table continued on following page) </TABLE> F-20
58 <TABLE> <CAPTION> UNITED STATES CANADA TRINIDAD INDIA OTHER TOTAL ------------- -------- -------- -------- -------- ---------- <S> <C> <C> <C> <C> <C> <C> 1996 Net Operating Revenues............. $ 563,346 $ 63,076 $ 83,536 $ 20,691 $ (1) $ 730,648 Depreciation, Depletion and Amortization..................... 209,635 24,935 15,447 611 650 251,278 Operating Income (Loss)............ 160,109 12,720 48,962 5,667 (18,628) 208,830 Interest Income.................... 959 44 836 412 13 2,264 Other Income (Expense)............. (4,569) 9 394 5 (3,110) (7,271) Interest Expense................... 9,006 7,969 4,003 1,019 - 21,997 Income Tax Provision (Benefit)..... 36,519 (10,508) 26,172 754 (1,983) 50,954 Additions to Oil and Gas Properties....................... 407,115 33,008 8,654 82,098 8,455 539,330 Total Assets....................... 1,882,900 236,925 129,896 180,225 28,407 2,458,353 </TABLE> 13. OTHER INCOME (EXPENSE), NET Other income (expense), net consisted of the following for the years ended December 31: <TABLE> <CAPTION> 1998 1997 1996 ------- ------- ------- <S> <C> <C> <C> Interest Income(1)...................................... $ 1,147 $ 4,122 $ 2,264 Financial Reserve Accruals(2)........................... (4,350) - (6,897) Contract Settlement..................................... (610) - - Litigation Provision.................................... - (5,800) - Other, Net.............................................. (987) 90 (374) ------- ------- ------- Total......................................... $(4,800) $(1,588) $(5,007) ======= ======= ======= </TABLE> - --------------- (1) Includes $102, $2,549 and $403 from related parties. (2) Pertains to provisions for doubtful accounts receivable associated with certain international activities. 14. PRICE AND INTEREST RATE RISK MANAGEMENT Periodically, the Company enters into certain trading and non-trading activities including NYMEX-related commodity market transactions and other contracts. The non-trading portions of these activities have been designated to hedge the impact of market price fluctuations on anticipated commodity delivery volumes or other contractual commitments. Trading Activities. Trading activities in 1998 included a revenue increase of $1.1 million related to change in market value of natural gas price swap options exercisable by a counterparty and partially offsetting "buy" price swap positions. During 1995, the Company entered into a NYMEX-related natural gas price swap covering 73 trillion British thermal units ("TBtu") for the year ended December 31, 1996. This swap contained an option to extend the price swap covering 73 TBtu for each of the years 1997 and 1998 which was exercisable at one time prior to December 31, 1996. The 1996 price swap was closed in the first quarter of 1996. During 1996, this option was restructured into four options each exercisable, in total, at one time by the counterparty before December 31, 1996, 1997, 1998 and 1999 to purchase 37 TBtu of notional natural gas for each of the years 1997, 1998, 1999 and 2000 at an average fixed price of $1.98, $1.98, $1.93 and $1.93 per million British thermal units ("MMBtu"), respectively. The 1997 and 1998 options were subsequently restructured to be exercisable monthly at a price of $2.16 and $2.07 per MMBtu, respectively. These options cover notional volumes averaging 3 TBtu per month during 1997 and 1998. During the fourth quarter of 1996, the 1999 and 2000 options were terminated. In 1996, the Company entered into "buy" NYMEX-related natural gas price swap positions in the same notional quantities and maturities as are covered by the 1997 and 1998 options. The Company recognized a $1.1 million and $3.4 million revenue increase in 1998 and 1997, respectively, and a $12 million revenue reduction in 1996 related to these trading activities. F-21
59 The following table summarizes the estimated fair value of financial instruments held for trading purposes at year-end and the average during the year: <TABLE> <CAPTION> ESTIMATED FAIR VALUES(1) (IN MILLIONS) ---------------------------------------------------- 1998 1997 1996 -------------- ---------------- ---------------- YEAR YEAR YEAR END AVERAGE END AVERAGE END AVERAGE ---- ------- ------ ------- ------ ------- <S> <C> <C> <C> <C> <C> <C> Options Written..................... $ - $(5.1) $(10.5) $(13.7) $(12.8) $(8.3) NYMEX-related Natural Gas Price Swaps............................. - 5.0 4.2 7.1 0.8 3.4 </TABLE> - --------------- (1) Estimated fair values have been determined by using available market data and valuation methodologies. Judgment is necessarily required in interpreting market data and the use of different market assumptions or estimation methodologies may affect the estimated fair value amounts. Interest Rate Swap Agreements and Foreign Currency Contracts. At December 31, 1998 and 1997, a subsidiary of the Company and the Company are parties to offsetting foreign currency and interest rate swap agreements with an aggregate notional principal amount of $210 million. Such swap agreements are scheduled to terminate in 2001. At December 31, 1998 and 1997, the composite fair value of the agreements was not significant based upon termination values obtained from third parties. In November 1998, the Company entered into two interest rate swap agreements having notional values of $100 million each. The agreements were entered into to hedge the base variable interest rates of the Company's commercial paper, uncommitted credit facilities and affiliate borrowings. The Company anticipates having such borrowings outstanding of at least the notional amounts under the swap agreements during the term of the swap agreements. Under the agreements, the Company will pay interest based on fixed rates of approximately 4.96% and 5.01% and receive interest based on the three-month LIBOR calculated on the notional value of the swap agreements. These agreements are scheduled to terminate in November 2000. At December 31, 1998, the composite fair value of these agreements was not significant based upon termination values obtained from third parties. Hedging Transactions. With the objective of enhancing the certainty of future revenues, the Company from time to time enters into NYMEX-related commodity price swaps and costless collars. Using NYMEX-related commodity price swaps, the Company receives a fixed price for the respective commodity hedged and pays a floating market price, as defined for each transaction, to the counterparty at settlement. At December 31, 1998, the Company had outstanding positions covering notional volumes of .7 million barrels ("MMBbl") of crude oil and condensate for 1999. The fair value of the positions was a net revenue increase of approximately $4 million. In 1998, the Company closed positions covering notional volumes of approximately 4 TBtu of natural gas for each of the years 1999 through 2005. The Company also recorded closed positions covering 2.2 MMBbl and 1.7 MMBbl of crude oil and condensate for the years 1999 and 2000, respectively. At December 31, 1998, the aggregate deferred revenue reduction for 1999, 2000 and thereafter was approximately $13 million, $12 million and $6 million, respectively, and is classified as "Other Assets". At December 31, 1997, the Company had outstanding positions covering notional volumes of approximately 37 TBtu of natural gas for 1998 and approximately 4 TBtu of natural gas for each of the years 1999 and 2000 and approximately 1.3 MMBbl and .7 MMBbl of crude oil and condensate for the years 1998 and 1999, respectively. The fair value of the positions was a net revenue increase of $1 million at December 31, 1997. During the fourth quarter of 1997, the Company closed positions covering notional volumes of approximately 37 TBtu of natural gas for each of the years 1999 and 2000. At December 31, 1997, the aggregate deferred revenue reduction for the 1998, 1999 and 2000 closed positions was approximately $9 million, $10 million and $10 million, respectively. F-22
60 The following table summarizes the estimated fair value of financial instruments and related transactions for non-trading activities at December 31, 1998 and 1997: <TABLE> <CAPTION> 1998 1997 ------------------------ ------------------------ CARRYING ESTIMATED CARRYING ESTIMATED AMOUNT FAIR VALUE(1) AMOUNT FAIR VALUE(1) -------- ------------- -------- ------------- (IN MILLIONS) (IN MILLIONS) <S> <C> <C> <C> <C> Long-Term Debt(2)....................... $1,142.8 $1,141.0 $741.3 $744.4 Swap Agreements......................... 4.2 4.1 13.3 12.7 NYMEX-Related Commodity Market Positions............................. (30.9) (26.5) (27.4) (31.6) </TABLE> - --------------- (1) Estimated fair values have been determined by using available market data and valuation methodologies. Judgment is necessarily required in interpreting market data and the use of different market assumptions or estimation methodologies may affect the estimated fair value amounts. (2) See Note 4 "Long-Term Debt." Credit Risk. While notional contract amounts are used to express the magnitude of price and interest rate swap agreements, the amounts potentially subject to credit risk, in the event of nonperformance by the other parties, are substantially smaller. The Company does not anticipate nonperformance by the other parties. 15. CONCENTRATION OF CREDIT RISK Substantially all of the Company's accounts receivable at December 31, 1998 and 1997 result from crude oil and natural gas sales and/or joint interest billings to affiliate and third party companies including foreign state-owned entities in the oil and gas industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. In determining whether or not to require collateral from a customer or joint interest owner, the Company analyzes the entity's net worth, cash flows, earnings, and credit ratings. Receivables are generally not collateralized. Historical credit losses incurred on receivables by the Company have been immaterial. 16. NEW ACCOUNTING PRONOUNCEMENT - SFAS NO. 133 In June 1998, the Financial Accounting Standards Board ("FASB") issued SFAS No. 133 - "Accounting for Derivative Instruments and Hedging Activities" effective for fiscal years beginning after June 15, 1999. The statement cannot be applied retroactively and must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts that were issued, acquired or substantively modified after December 31, 1997. The statement establishes accounting and reporting standards requiring that every derivative instrument be recorded in the balance sheet as either an asset or liability measured at its fair value. The statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the statements of income and requires a company to formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment. F-23
61 The Company has not yet quantified the impacts of adopting SFAS No. 133 on its financial statements and has not determined the timing of adoption. Based on the criteria of SFAS No. 133 and current interpretations thereof, the Company believes that the options it owns to purchase 3,200,000 Enron Corp. common shares, at a price of $39.1875 per share that expire in December 2007, qualify as derivative instruments. Accordingly, SFAS No. 133 would require the changes in the fair value of the options to be recognized currently in earnings. The Company cannot predict whether future interpretations currently being considered by the Emerging Issues Task Force of the FASB or potential amendments of SFAS No. 133 will result in the options being considered derivative instruments at the time of its adoption. At December 31, 1997, the carrying value of the options was approximately $23 million pre-tax, which represented the estimated fair value at the date of grant. At December 31, 1998, Enron Corp. common shares closed at $57.06 per share. Based on the Company's current level of other derivative and hedging activities, the Company does not expect the impact of adoption of SFAS No. 133 relative to those other activities to be material. F-24
62 ENRON OIL & GAS COMPANY SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (IN THOUSANDS EXCEPT PER SHARE AMOUNTS UNLESS OTHERWISE INDICATED) (UNAUDITED EXCEPT FOR RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES) OIL AND GAS PRODUCING ACTIVITIES The following disclosures are made in accordance with SFAS No. 69 - "Disclosures about Oil and Gas Producing Activities": Oil and Gas Reserves. Users of this information should be aware that the process of estimating quantities of "proved", "proved developed" and "proved undeveloped" crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time 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. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Proved reserves represent estimated quantities of natural gas, crude oil, condensate, and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. Proved developed reserves are proved reserves expected to be recovered, through wells and equipment in place and under operating methods being utilized at the time the estimates were made. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices and production volumes. Canadian reserves, as presented on a net basis, assume prices and royalty rates in existence at the time the estimates were made, and the Company's estimate of future production volumes. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause the Company's share of future production from Canadian reserves to be materially different from that presented. Estimates of proved and proved developed reserves at December 31, 1998, 1997 and 1996 were based on studies performed by the engineering staff of the Company for reserves in the United States, Canada, Trinidad, India and China. Opinions by DeGolyer and MacNaughton ("D&M"), independent petroleum consultants, for the years ended December 31, 1998, 1997 and 1996 covered producing areas containing 39%, 54% and 64%, respectively, of proved reserves, excluding deep Paleozoic methane reserves, of the Company on a net-equivalent-cubic-feet-of-gas basis. D&M's opinions indicate that the estimates of proved reserves prepared by the Company's engineering staff for the properties reviewed by D&M, when compared in total on a net-equivalent-cubic-feet-of-gas basis, do not differ materially from the estimates prepared by D&M. The deep Paleozoic methane reserves were covered by the opinion of D&M for the year ended December 31, 1995. Such estimates by D&M in the aggregate varied by not more than 5% from those prepared by the engineering F-25
63 staff of the Company. The India reserves, which accounted for 23% of the Company's December 31, 1998 proved reserves, excluding deep Paleozoic reserves, were not included in the year end review by D&M; however, a review was conducted as of April 30, 1998. The estimate of the India reserves prepared by D&M varied by not more than 10% from the estimate prepared by the engineering staff of the Company. All reports by D&M were developed utilizing geological and engineering data provided by the Company. No major discovery or other favorable or adverse event subsequent to December 31, 1998 is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date. The following table sets forth the Company's net proved and proved developed reserves at December 31 for each of the four years in the period ended December 31, 1998, and the changes in the net proved reserves for each of the three years in the period then ended as estimated by the engineering staff of the Company. NET PROVED AND PROVED DEVELOPED RESERVE SUMMARY <TABLE> <CAPTION> UNITED STATES CANADA TRINIDAD INDIA OTHER TOTAL ------------- ------- -------- ------- ----- ------- <S> <C> <C> <C> <C> <C> <C> Natural Gas (Bcf)(1) Net proved reserves at December 31, 1995.................................... 2,654.1(2) 313.9 245.5 75.0 - 3,288.5 Revisions of previous estimates......... 3.6 (2.9) 79.6 - - 80.3 Purchases in place...................... 100.6 0.9 - - - 101.5 Extensions, discoveries and other additions............................ 256.8 49.2 90.7 124.6 - 521.3 Sales in place.......................... (58.4) (4.3) - - - (62.7) Production.............................. (210.2) (35.9) (45.6) - - (291.7) ------- ------- ------- ------- ------- ------- Net proved reserves at December 31, 1996.................................... 2,746.5(2) 320.9 370.2 199.6 - 3,637.2 Revisions of previous estimates......... (50.8) (1.5) (0.4) 25.1 - (27.6) Purchases in place...................... 60.0 67.6 - - - 127.6 Extensions, discoveries and other additions............................ 275.9 37.8 - 253.5 7.7 574.9 Sales in place.......................... (17.7) (0.4) - - - (18.1) Production.............................. (229.1) (37.0) (41.0) (6.6) - (313.7) ------- ------- ------- ------- ------- ------- Net proved reserves at December 31, 1997.................................... 2,784.8(2) 387.4 328.8 471.6 7.7 3,980.3 Revisions of previous estimates......... (55.9) (2.5) 4.7 32.3 (0.4) (21.8) Purchases in place...................... 123.0 54.9 - - - 177.9 Extensions, discoveries and other additions............................ 272.8 62.9 693.8 340.9 103.0 1,473.4 Sales in place.......................... (37.5) - - - - (37.5) Production.............................. (233.8) (38.5) (50.9) (20.2) - (343.4) ------- ------- ------- ------- ------- ------- Net proved reserves at December 31, 1998.................................... 2,853.4(2) 464.2 976.4 824.6 110.3 5,228.9 ======= ======= ======= ======= ======= ======= (Table continued on following page) </TABLE> F-26
64 <TABLE> <CAPTION> UNITED STATES CANADA TRINIDAD INDIA OTHER TOTAL ------------- ------- -------- ------- ----- ------- <S> <C> <C> <C> <C> <C> <C> Liquids (MBbl)(3)(4) Net proved reserves at December 31, 1995.................................... 25,399 6,585 6,870 11,542 - 50,396 Revisions of previous estimates......... 339 191 1,835 - - 2,365 Purchases in place...................... 312 2 - - - 314 Extensions, discoveries and other additions............................ 7,103 2,116 1,388 275 - 10,882 Sales in place.......................... (447) (121) - - - (568) Production.............................. (3,830) (1,321) (1,925) (1,026) - (8,102) ------- ------- ------- ------- ------- ------- Net proved reserves at December 31, 1996.................................... 28,876 7,452 8,168 10,791 - 55,287 Revisions of previous estimates......... 3,515 225 (31) 19 - 3,728 Purchases in place...................... 127 1,123 - - - 1,250 Extensions, discoveries and other additions............................ 6,037 1,590 - 20,123 - 27,750 Sales in place.......................... (1,683) - - - - (1,683) Production.............................. (5,223) (1,384) (1,236) (838) - (8,681) ------- ------- ------- ------- ------- ------- Net proved reserves at December 31, 1997.................................... 31,649 9,006 6,901 30,095 - 77,651 Revisions of previous estimates......... (152) (504) (1,049) 3,063 73 1,431 Purchases in place...................... 3,104 - - - - 3,104 Extensions, discoveries and other additions............................ 9,396 448 11,429 11,501 1,089 33,863 Sales in place.......................... (1,039) - - - - (1,039) Production.............................. (6,131) (1,358) (1,077) (1,874) - (10,440) ------- ------- ------- ------- ------- ------- Net proved reserves at December 31, 1998.................................... 36,827 7,592 16,204 42,785 1,162 104,570 ======= ======= ======= ======= ======= ======= Bcf Equivalent (Bcfe)(1) Net proved reserves at December 31, 1995.................................... 2,806.6(2) 353.3 286.7 144.3 - 3,590.9 Revisions of previous estimates......... 5.7 (1.8) 90.6 - - 94.5 Purchases in place...................... 102.5 0.9 - - - 103.4 Extensions, discoveries and other additions............................ 299.4 61.9 99.0 126.2 - 586.5 Sales in place.......................... (61.0) (5.1) - - - (66.1) Production.............................. (233.1) (43.9) (57.1) (6.2) - (340.3) ------- ------- ------- ------- ------- ------- Net proved reserves at December 31, 1996.................................... 2,920.1(2) 365.3 419.2 264.3 - 3,968.9 Revisions of previous estimates......... (29.8) (0.1) (0.5) 25.2 - (5.2) Purchases in place...................... 60.7 74.4 - - - 135.1 Extensions, discoveries and other additions............................ 312.1 47.4 - 374.2 7.7 741.4 Sales in place.......................... (27.7) (0.4) - - - (28.1) Production.............................. (260.4) (45.3) (48.5) (11.7) - (365.9) ------- ------- ------- ------- ------- ------- Net proved reserves at December 31, 1997.................................... 2,975.0(2) 441.3 370.2 652.0 7.7 4,446.2 Revisions of previous estimates......... (57.0) (5.5) (1.7) 50.8 - (13.4) Purchases in place...................... 141.6 54.9 - - - 196.5 Extensions, discoveries and other additions............................ 329.2 65.6 762.4 409.9 109.5 1,676.6 Sales in place.......................... (43.7) - - - - (43.7) Production.............................. (270.6) (46.6) (57.3) (31.4) - (405.9) ------- ------- ------- ------- ------- ------- Net proved reserves at December 31, 1998.................................... 3,074.5(2) 509.7 1,073.6 1,081.3 117.2 5,856.3 ======= ======= ======= ======= ======= ======= (Table continued on following page) </TABLE> F-27
65 <TABLE> <CAPTION> UNITED STATES CANADA TRINIDAD INDIA OTHER TOTAL ------------- ------- -------- ------- ----- ------- <S> <C> <C> <C> <C> <C> <C> Net proved developed reserves at Natural Gas (Bcf) December 31, 1995.................... 1,218.1 310.1 233.9 - - 1,762.1 December 31, 1996.................... 1,325.7 319.5 370.2 124.6 - 2,140.0 December 31, 1997.................... 1,349.0 370.9 328.8 286.6 - 2,335.3 December 31, 1998.................... 1,429.7 387.4 283.0 407.4 - 2,507.5 Liquids (MBbl)(4) December 31, 1995.................... 19,977 6,505 5,607 11,542 - 43,631 December 31, 1996.................... 24,868 7,452 8,168 10,791 - 51,279 December 31, 1997.................... 27,707 8,885 6,901 23,322 - 66,815 December 31, 1998.................... 33,045 7,465 4,782 33,472 - 78,764 Bcf Equivalents December 31, 1995.................... 1,338.0 349.1 267.5 69.3 - 2,023.9 December 31, 1996.................... 1,474.9 364.2 419.2 189.3 - 2,447.6 December 31, 1997.................... 1,515.3 424.2 370.2 426.5 - 2,736.2 December 31, 1998.................... 1,628.0 432.1 311.7 608.2 - 2,980.0 </TABLE> - --------------- (1) Billion cubic feet or billion cubic feet equivalent, as applicable. (2) Includes 1,180 Bcf of proved undeveloped methane reserves contained, along with high concentrations of carbon dioxide and other gases in deep Paleozoic (Madison) formations in the Big Piney area of Wyoming. (3) Thousand barrels. (4) Includes crude oil, condensate and natural gas liquids. Capitalized Costs Relating to Oil and Gas Producing Activities. The following table sets forth the capitalized costs relating to the Company's natural gas and crude oil producing activities at December 31, 1998 and 1997: <TABLE> <CAPTION> 1998 1997 ---------- ---------- <S> <C> <C> Proved Properties........................................... $4,630,353 $4,069,914 Unproved Properties......................................... 184,072 221,491 ---------- ---------- Total.................................................. 4,814,425 4,291,405 Accumulated depreciation, depletion and amortization........ (2,138,062) (1,904,198) ---------- ---------- Net capitalized costs....................................... $2,676,363 $2,387,207 ========== ========== </TABLE> Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities. The acquisition, exploration and development costs disclosed in the following tables are in accordance with definitions in SFAS No. 19 - "Financial Accounting and Reporting by Oil and Gas Producing Companies". Acquisition costs include costs incurred to purchase, lease, or otherwise acquire property. Exploration costs include exploration expenses, additions to exploration wells including those in progress, and depreciation of support equipment used in exploration activities. Development costs include additions to production facilities and equipment, additions to development wells including those in progress and depreciation of support equipment and related facilities used in development activities. F-28
66 The following tables set forth costs incurred related to the Company's oil and gas activities for the years ended December 31: <TABLE> <CAPTION> UNITED STATES CANADA TRINIDAD INDIA OTHER TOTAL ------------- ------- -------- ------- ------- -------- <S> <C> <C> <C> <C> <C> <C> 1998 Acquisition Costs of Properties Unproved...................... $ 32,925 $ 3,545 $ - $ - $ - $ 36,470 Proved........................ 198,006 12,896 - - - 210,902 -------- ------- ------- ------- ------- -------- Total................. 230,931 16,441 - - - 247,372 Exploration Costs............... 82,248 12,375 15,217 1,278 25,465 136,583 Development Costs............... 297,904 27,822 6,157 46,657 16,548 395,088 -------- ------- ------- ------- ------- -------- Total................. $611,083 $56,638 $21,374 $47,935 $42,013 $779,043 ======== ======= ======= ======= ======= ======== 1997 Acquisition Costs of Properties Unproved...................... $ 69,258 $ 7,700 $ - $ - $ 235 $ 77,193 Proved........................ 42,386 38,949 - - 28 81,363 -------- ------- ------- ------- ------- -------- Total................. 111,644 46,649 - - 263 158,556 Exploration Costs............... 74,360 8,279 1,344 965 15,935 100,883 Development Costs............... 333,093 30,856 163 67,777 9,869 441,758 -------- ------- ------- ------- ------- -------- Total................. $519,097 $85,784 $ 1,507 $68,742 $26,067 $701,197 ======== ======= ======= ======= ======= ======== 1996 Acquisition Costs of Properties Unproved...................... $ 38,832 $ 3,565 $ 2,000 $ - $ 77 $ 44,474 Proved........................ 68,706 672 - - - 69,378 -------- ------- ------- ------- ------- -------- Total................. 107,538 4,237 2,000 - 77 113,852 Exploration Costs............... 60,880 8,069 2,082 748 16,490 88,269 Development Costs............... 283,985 25,705 6,654 82,098 6,969 405,411 -------- ------- ------- ------- ------- -------- Total................. $452,403 $38,011 $10,736 $82,846 $23,536 $607,532 ======== ======= ======= ======= ======= ======== </TABLE> F-29
67 Results of Operations for Oil and Gas Producing Activities(1). The following tables set forth results of operations for oil and gas producing activities for the years ended December 31: <TABLE> <CAPTION> UNITED STATES CANADA TRINIDAD INDIA OTHER TOTAL -------- ------- -------- ------- -------- -------- <S> <C> <C> <C> <C> <C> <C> 1998 Operating Revenues Trade.................................... $431,943 $53,485 $66,967 $72,826 $ 52 $625,273 Associated Companies..................... 117,719 15,132 - - - 132,851 Gains on Sales of Reserves and Related Assets................................. 29,268 (15) - - (3,658) 25,595 -------- ------- ------- ------- -------- -------- Total............................. 578,930 68,602 66,967 72,826 (3,606) 783,719 Exploration Expenses, including Dry Hole... 63,875 7,496 2,027 1,278 14,015 88,691 Production Costs........................... 98,909 19,715 7,361 13,617 3,666 143,268 Impairment of Unproved Oil and Gas Properties............................... 29,952 2,124 - - - 32,076 Depreciation, Depletion and Amortization... 264,927 25,972 12,867 8,456 2,073 314,295 -------- ------- ------- ------- -------- -------- Income (Loss) before Income Taxes.......... 121,267 13,295 44,712 49,475 (23,360) 205,389 Income Tax Provision (Benefit)............. 22,944 3,840 24,592 23,748 (7,370) 67,754 -------- ------- ------- ------- -------- -------- Results of Operations...................... $ 98,323 $ 9,455 $20,120 $25,727 $(15,990) $137,635 ======== ======= ======= ======= ======== ======== 1997 Operating Revenues Trade.................................... $448,824 $58,712 $66,000 $35,332 $ 21 $608,889 Associated Companies..................... 206,738 15,280 - - 2 222,020 Gains on Sales of Reserves and Related Assets................................. 4,464 (13) - - 4,836 9,287 -------- ------- ------- ------- -------- -------- Total............................. 660,026 73,979 66,000 35,332 4,859 840,196 Exploration Expenses, including Dry Hole... 50,930 5,995 1,344 965 15,765 74,999 Production Costs........................... 106,395 20,073 12,256 10,505 75 149,304 Impairment of Unproved Oil and Gas Properties............................... 24,229 2,643 - - 341 27,213 Depreciation, Depletion and Amortization... 238,765 23,116 11,032 3,716 901 277,530 -------- ------- ------- ------- -------- -------- Income (Loss) before Income Taxes.......... 239,707 22,152 41,368 20,146 (12,223) 311,150 Income Tax Provision (Benefit)............. 69,252 8,130 22,752 9,670 (252) 109,552 -------- ------- ------- ------- -------- -------- Results of Operations...................... $170,455 $14,022 $18,616 $10,476 $(11,971) $201,598 ======== ======= ======= ======= ======== ======== 1996 Operating Revenues Trade.................................... $281,522 $48,717 $83,536 $20,691 $ - $434,466 Associated Companies..................... 253,629 13,715 - - - 267,344 Gains on Sales of Reserves and Related Assets................................. 19,127 670 - - - 19,797 -------- ------- ------- ------- -------- -------- Total............................. 554,278 63,102 83,536 20,691 - 721,607 Exploration Expenses, including Dry Hole... 45,291 5,003 2,082 748 15,078 68,202 Production Costs........................... 77,352 16,633 14,577 9,890 - 118,452 Impairment of Unproved Oil and Gas Properties............................... 18,571 2,284 - - 371 21,226 Depreciation, Depletion and Amortization... 208,872 24,935 15,447 611 648 250,513 -------- ------- ------- ------- -------- -------- Income (Loss) before Income Taxes.......... 204,192 14,247 51,430 9,442 (16,097) 263,214 Income Tax Provision (Benefit)............. 54,412 5,674 28,287 4,721 (50) 93,044 -------- ------- ------- ------- -------- -------- Results of Operations...................... $149,780 $ 8,573 $23,143 $ 4,721 $(16,047) $170,170 ======== ======= ======= ======= ======== ======== </TABLE> - --------------- (1) Excludes net revenues associated with other marketing activities, interest charges, general corporate expenses and certain gathering and handling fees for each of the three years in the period ended December 31, 1998. The gathering and handling fees and other marketing net revenues are directly associated with oil and gas operations with regard to segment reporting as defined in SFAS No. 131 - "Disclosures about Segments of an Enterprise and Related Information", but are not part of Disclosures about Oil and Gas Producing Activities as defined in SFAS No. 69. F-30
68 Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves. The following information has been developed utilizing procedures prescribed by SFAS No. 69 and based on crude oil and natural gas reserve and production volumes estimated by the engineering staff of the Company. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company. The future cash flows presented below are based on sales prices, cost rates, and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used. Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated. F-31
69 The following table sets forth the standardized measure of discounted future net cash flows from projected production of the Company's crude oil and natural gas reserves at December 31, for the years ended December 31: <TABLE> <CAPTION> UNITED STATES CANADA TRINIDAD INDIA OTHER TOTAL ------------- -------- ---------- ---------- -------- ----------- <S> <C> <C> <C> <C> <C> <C> 1998 Future cash inflows(1)................... $5,471,121 $950,151 $1,210,060 $2,384,459 $179,329 $10,195,120 Future production costs.................. (1,280,875) (319,938) (347,431) (556,609) (127,039) (2,631,892) Future development costs................. (316,175) (42,252) (161,424) (392,546) (11,325) (923,722) ---------- -------- ---------- ---------- -------- ----------- Future net cash flows before income taxes.................................. 3,874,071 587,961 701,205 1,435,304 40,965 6,639,506 Future income taxes...................... (903,983) (119,655) (229,281) (614,297) (7,111) (1,874,327) ---------- -------- ---------- ---------- -------- ----------- Future net cash flows.................... 2,970,088 468,306 471,924 821,007 33,854 4,765,179 Discount to present value at 10% annual rate................................... (1,399,541) (161,988) (234,129) (434,714) (13,893) (2,244,265) ---------- -------- ---------- ---------- -------- ----------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves(2).................... $1,570,547 $306,318 $ 237,795 $ 386,293 $ 19,961 $ 2,520,914 ========== ======== ========== ========== ======== =========== 1997 Future cash inflows(1)................... $5,186,755 $814,195 $ 532,318 $1,633,199 $ 13,862 $ 8,180,329 Future production costs.................. (1,138,401) (302,965) (106,999) (422,474) (3,587) (1,974,426) Future development costs................. (313,463) (19,610) (400) (102,014) (1,814) (437,301) ---------- -------- ---------- ---------- -------- ----------- Future net cash flows before income taxes.................................. 3,734,891 491,620 424,919 1,108,711 8,461 5,768,602 Future income taxes...................... (887,521) (92,927) (215,344) (501,109) (779) (1,697,680) ---------- -------- ---------- ---------- -------- ----------- Future net cash flows.................... 2,847,370 398,693 209,575 607,602 7,682 4,070,922 Discount to present value at 10% annual rate................................... (1,297,651) (121,381) (61,656) (287,874) (1,906) (1,770,468) ---------- -------- ---------- ---------- -------- ----------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves....................... $1,549,719 $277,312 $ 147,919 $ 319,728 $ 5,776 $ 2,300,454 ========== ======== ========== ========== ======== =========== 1996 Future cash inflows(1)................... $9,390,661 $715,143 $ 709,082 $ 864,386 $ - $11,679,272 Future production costs.................. (1,639,531) (281,244) (236,643) (338,202) - (2,495,620) Future development costs................. (306,028) (9,014) (1,588) (150) - (316,780) ---------- -------- ---------- ---------- -------- ----------- Future net cash flows before income taxes.................................. 7,445,102 424,885 470,851 526,034 - 8,866,872 Future income taxes...................... (2,260,500) (98,606) (245,577) (227,177) - (2,831,860) ---------- -------- ---------- ---------- -------- ----------- Future net cash flows.................... 5,184,602 326,279 225,274 298,857 - 6,035,012 Discount to present value at 10% annual rate................................... (2,692,833) (100,521) (68,436) (104,672) - (2,966,462) ---------- -------- ---------- ---------- -------- ----------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves....................... $2,491,769 $225,758 $ 156,838 $ 194,185 $ - $ 3,068,550 ========== ======== ========== ========== ======== =========== </TABLE> - --------------- (1) Based on year end market prices determined at the point of delivery from the producing unit. (2) Based on natural gas and crude oil prices as of March 1, 1999, the standardized measure of discounted future net cash flows for operations in the United States would have been lower by approximately 23%. Changes in other producing areas and changes in reported reserve quantities were not material. F-32
70 Changes in Standardized Measure of Discounted Future Net Cash Flows. The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for each of the three years in the period ended December 31, 1998. <TABLE> <CAPTION> UNITED STATES CANADA TRINIDAD INDIA OTHER TOTAL ------------- -------- -------- --------- ------- ---------- <S> <C> <C> <C> <C> <C> <C> December 31, 1995....................... $1,240,140(1) $176,573 $115,026 $ 53,401 $ - $1,585,140 Sales and transfers of oil and gas produced, net of production costs... (437,143) (45,799) (68,959) (10,801) - (562,702) Net changes in prices and production costs............................... 1,817,466 57,587 60,387 53,676 - 1,989,116 Extensions, discoveries, additions and improved recovery net of related costs............................... 580,417 62,506 62,165 150,475 - 855,563 Development costs incurred............ 57,800 2,200 2,200 - - 62,200 Revisions of estimated development costs............................... (14,490) (2,696) 1,010 13,500 - (2,676) Revisions of previous quantity estimates........................... 7,002 (1,227) 79,933 - - 85,708 Accretion of discount................. 137,441 18,387 19,376 8,928 - 184,132 Net change in income taxes............ (655,801) (29,814) (73,985) (86,627) - (846,227) Purchases of reserves in place........ 161,454 456 - - - 161,910 Sales of reserves in place............ (102,671) (3,561) - - - (106,232) Changes in timing and other........... (299,846) (8,854) (40,315) 11,633 - (337,382) ---------- -------- -------- --------- ------- ---------- December 31, 1996....................... 2,491,769(1) 225,758 156,838 194,185 - 3,068,550 Sales and transfers of oil and gas produced, net of production costs... (518,594) (53,919) (53,744) (24,827) - (651,084) Net changes in prices and production costs............................... (1,664,174) (19,784) 4,730 (34,611) - (1,713,839) Extensions, discoveries, additions and improved recovery net of related costs............................... 374,283 37,533 - 257,256 5,616 674,688 Development costs incurred............ 52,300 1,900 - - - 54,200 Revisions of estimated development costs............................... 3,681 4,345 1,188 (33,210) - (23,996) Revisions of previous quantity estimates........................... (17,257) (101) (442) 26,696 - 8,896 Accretion of discount................. 327,724 26,287 30,956 31,669 - 416,636 Net change in income taxes............ 605,769 11,097 12,734 (90,729) 160 539,031 Purchases of reserves in place........ 43,882 52,911 - - - 96,793 Sales of reserves in place............ (28,589) (379) - - - (28,968) Changes in timing and other........... (121,075) (8,336) (4,341) (6,701) - (140,453) ---------- -------- -------- --------- ------- ---------- December 31, 1997....................... 1,549,719(1) 277,312 147,919 319,728 5,776 2,300,454 Sales and transfers of oil and gas produced, net of production costs... (423,733) (48,902) (59,606) (59,209) 3,664 (587,786) Net changes in prices and production costs............................... (33,809) 10,891 (36,730) (103,097) (6,961) (169,706) Extensions, discoveries, additions and improved recovery net of related costs............................... 325,308 43,686 159,497 218,168 18,894 765,553 Development costs incurred............ 59,600 2,900 6,000 43,400 4,300 116,200 Revisions of estimated development costs............................... (26,611) 690 (11,410) (66,128) (3,233) (106,692) Revisions of previous quantity estimates........................... (35,216) (4,137) (1,142) 36,877 - (3,618) Accretion of discount................. 174,102 30,332 28,791 53,296 562 287,083 Net change in income taxes............ 47,745 (5,822) (122) 212 (428) 41,585 Purchases of reserves in place........ 156,818 20,131 - - - 176,949 Sales of reserves in place............ (33,549) - - - - (33,549) Changes in timing and other........... (189,827) (20,763) 4,598 (56,954) (2,613) (265,559) ---------- -------- -------- --------- ------- ---------- December 31, 1998....................... $1,570,547(1) $306,318 $237,795 $ 386,293 $19,961 $2,520,914 ========== ======== ======== ========= ======= ========== </TABLE> - --------------- (1) Includes approximately $77,500, $344,300, $85,700 and $155,400, discounted before income taxes, in 1995, 1996, 1997 and 1998, respectively, related to the reserves in the Big Piney deep Paleozoic formations. F-33
71 UNAUDITED QUARTERLY FINANCIAL INFORMATION <TABLE> <CAPTION> QUARTER ENDED -------------------------------------------- MARCH 31 JUNE 30 SEPT. 30 DEC. 31 -------- -------- -------- -------- <S> <C> <C> <C> <C> 1998 Net Operating Revenues.......................... $199,831 $183,307 $191,262 $194,788 ======== ======== ======== ======== Operating Income................................ $ 38,286 $ 32,669 $ 19,199 $ 23,507 ======== ======== ======== ======== Income before Income Taxes...................... $ 28,206 $ 22,173 $ 3,969 $ 5,934 Income Tax Provision (Benefit).................. 1,201 8,916 (1,975) (4,031) -------- -------- -------- -------- Net Income...................................... $ 27,005 $ 13,257 $ 5,944 $ 9,965 ======== ======== ======== ======== Net Income per Share of Common Stock Basic......................................... $ .17 $ .09 $ .04 $ .06 ======== ======== ======== ======== Diluted....................................... $ .17 $ .09 $ .04 $ .06 ======== ======== ======== ======== Average Number of Common Shares Basic......................................... 154,736 154,857 154,083 153,702 ======== ======== ======== ======== Diluted....................................... 155,522 155,770 154,409 154,516 ======== ======== ======== ======== 1997 Net Operating Revenues.......................... $180,651 $171,753 $193,120 $237,977 ======== ======== ======== ======== Operating Income................................ $ 41,170 $ 28,619 $ 48,757 $ 74,229 ======== ======== ======== ======== Income before Income Taxes...................... $ 37,311 $ 24,111 $ 40,975 $ 61,073 Income Tax Provision (Benefit).................. 14,246 (460) 9,802 17,912 -------- -------- -------- -------- Net Income...................................... $ 23,065 $ 24,571 $ 31,173 $ 43,161 ======== ======== ======== ======== Net Income per Share of Common Stock Basic......................................... $ .15 $ .16 $ .20 $ .28 ======== ======== ======== ======== Diluted....................................... $ .14 $ .16 $ .20 $ .28 ======== ======== ======== ======== Average Number of Common Shares Basic......................................... 158,866 157,489 157,072 156,076 ======== ======== ======== ======== Diluted....................................... 159,790 157,950 158,049 156,808 ======== ======== ======== ======== 1996 Net Operating Revenues.......................... $159,026 $197,113 $170,182 $204,327 ======== ======== ======== ======== Operating Income................................ $ 31,997 $ 73,643 $ 46,179 $ 57,011 ======== ======== ======== ======== Income before Income Taxes...................... $ 27,338 $ 70,332 $ 43,361 $ 49,931 Income Tax Provision............................ 1,415 22,750 11,994 14,795 -------- -------- -------- -------- Net Income...................................... $ 25,923 $ 47,582 $ 31,367 $ 35,136 ======== ======== ======== ======== Net Income per Share of Common Stock Basic...... $ .16 $ .30 $ .20 $ .22 ======== ======== ======== ======== Diluted....................................... $ .16 $ .29 $ .19 $ .22 ======== ======== ======== ======== Average Number of Common Shares Basic......................................... 159,934 159,910 159,850 159,719 ======== ======== ======== ======== Diluted....................................... 161,411 161,656 161,677 161,352 ======== ======== ======== ======== </TABLE> F-34
72 SCHEDULE II ENRON OIL & GAS COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (IN THOUSANDS) <TABLE> <CAPTION> COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - -------- -------- -------- -------- -------- ADDITIONS DEDUCTIONS BALANCE AT CHARGED TO FOR PURPOSE FOR BALANCE AT BEGINNING OF COSTS AND WHICH RESERVES END OF DESCRIPTION YEAR EXPENSES WERE CREATED YEAR - ----------- ------------ ---------- --------------- ---------- <S> <C> <C> <C> <C> 1998 Reserves deducted from assets to which they apply - Allowance for Doubtful Accounts Receivable........................ $7,025 $4,350 $ - $11,375 ====== ====== ====== ======= 1997 Reserves deducted from assets to which they apply - Allowance for Doubtful Accounts Receivable........................ $7,030 $ - $ 5 $ 7,025 ====== ====== ====== ======= 1996 Reserves deducted from assets to which they apply - Allowance for Doubtful Accounts Receivable........................ $2,571 $6,897 $2,438 $ 7,030 ====== ====== ====== ======= </TABLE> S-1
73 EXHIBITS Exhibits not incorporated herein by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated herein by reference to the Company's Form S-1 Registration Statement, Registration No. 33-30678, filed on August 24, 1989 ("Form S-1"), or as otherwise indicated. <TABLE> <CAPTION> EXHIBIT NUMBER DESCRIPTION -------------- ----------- <C> <S> <C> 3.1(a) - Restated Certificate of Incorporation of Enron Oil & Gas Company (Exhibit 3.1 to Form S-1). 3.1(b) - Certificate of Amendment of Restated Certificate of Incorporation of Enron Oil & Gas Company (Exhibit 4.1(b) to Form S-8 Registration Statement No. 33-52201, filed February 8, 1994). 3.1(c) - Certificate of Amendment of Restated Certificate of Incorporation of Enron Oil & Gas Company (Exhibit 4.1(c) to Form S-8 Registration Statement No. 33-58103, filed March 15, 1995). 3.1(d) - Certificate of Amendment of Restated Certificate of Incorporation of Enron Oil & Gas Company, dated June 11, 1996 (Exhibit 3(d) to Form S-3 Registration Statement No. 333-09919, filed August 9, 1996). 3.1(e) - Certificate of Amendment of Restated Certificate of Incorporation of Enron Oil & Gas Company, dated May 7, 1997 (Exhibit 3(e) to Form S-3 Registration Statement No. 333-44785, filed January 23, 1998). *3.2 - By-laws of Enron Oil & Gas Company dated August 23, 1989, as amended December 12, 1990, February 8, 1994, January 19, 1996, February 13, 1997 and May 5, 1998. 3.3 - Specimen of Certificate evidencing the Common Stock (Exhibit 3.3 to Form S-1). 4.3(a) - Amended and Restated Enron Oil & Gas Company 1994 Stock Plan (Exhibit 4.3 to Form S-8 Registration Statement No. 33-58103, filed March 15, 1995). 4.3(b) - Amendment to Amended and Restated Enron Oil & Gas Company 1994 Stock Plan, dated effective as of December 12, 1995 (Exhibit 4.3(a) to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). 4.3(c) - Amendment to Amended and Restated Enron Oil & Gas Company 1994 Stock Plan, dated effective as of December 10, 1996 (Exhibit 4.3(a) to Form S-8 Registration Statement No. 333-20841, filed January 31, 1997). 4.3(d) - Third Amendment to Amended and Restated Enron Oil & Gas Company 1994 Stock Plan, dated effective as of December 9, 1997 (Exhibit 4.3(d) to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). *4.3(e) - Fourth Amendment to Amended and Restated Enron Oil & Gas Company 1994 Stock Plan, dated effective as of May 5, 1998. *4.3(f) - Fifth Amendment to Amended and Restated Enron Oil & Gas Company 1994 Stock Plan, dated effective as of December 8, 1998. 10.2(a) - Stock Restriction and Registration Agreement dated as of August 23, 1989 (Exhibit 10.2 to Form S-1). 10.2(b) - Amendment to Stock Restriction and Registration Agreement, dated December 9, 1997, between Enron Oil & Gas Company and Enron Corp. (Exhibit 10.2(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). *10.3 - Tax Allocation Agreement, entered into effective as of Deconsolidation Date between Enron Corp., Enron Oil & Gas Company, and the subsidiaries of Enron Oil & Gas Company listed therein as additional parties. </TABLE> E-1
74 <TABLE> <CAPTION> EXHIBIT NUMBER DESCRIPTION -------------- ----------- <C> <S> <C> 10.9(a) - Employment Agreement between Enron Oil & Gas Company and Forrest Hoglund, dated as of September 1, 1987, as amended (Exhibit 10.19 to Form S-1), and Second and Third Amendments to Employment Agreement dated June 30, 1989 and February 14, 1992, respectively (Exhibit 10.10 to Form S-1 Registration Statement No. 33-50462, filed August 5, 1992). 10.9(b) - 4th Amendment to Employment Agreement dated December 14, 1994, among Enron Corp., Enron Oil & Gas Company and Forrest Hoglund (Exhibit 10.9(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). *10.9(c) - Fifth Amendment to Employment Agreement entered into September 8, 1998, and effective as of September 1, 1998, among Enron Corp., Enron Oil & Gas Company and Forrest E. Hoglund. 10.14(a) - Enron Oil & Gas Company 1993 Nonemployee Directors' Stock Option Plan (Exhibit 10.14 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992). 10.14(b) - First Amendment to Enron Oil & Gas Company 1993 Nonemployee Directors' Stock Option Plan (Exhibit 10.14(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1996). 10.16 - Interest Rate and Currency Exchange Agreement, dated as of June 1, 1991, between Enron Risk Management Services Corp. and Enron Oil & Gas Marketing, Inc. (Exhibit 10.17 to the Company's Annual Report on Form 10-K for the year ended December 31, 1991), Confirmation dated June 14, 1992 (Exhibit 10.17 to Form S-1 Registration Statement, No. 33-50462, filed August 5, 1992) and Confirmations dated March 25, 1991, April 25, 1991, and September 23, 1992 (assigned to Enron Risk Management Services Corp. by Enron Finance Corp. pursuant to an Assignment and Assumption Agreement, dated as of November 1, 1993, by and between Enron Finance Corp., Enron Risk Management Services Corp. and Enron Oil & Gas Marketing, Inc.). (Exhibit 10.16 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.17 - Assignment and Assumption Agreement, dated as of November 1, 1993, by and between Enron Oil & Gas Marketing, Inc., Enron Oil & Gas Company and Enron Risk Management Services Corp. (Exhibit 10.17 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.18 - ISDA Master Agreement, dated as of November 1, 1993, between Enron Oil & Gas Company and Enron Risk Management Services Corp., and Confirmation Nos. 1268.0, 1286.0, 1291.0, 1292.0, 1304.0, 1305.0, 1321.0, 1335.0, 1338.0, 1370.0, 1471.0, 1485.0, 1486.0, 1494.0, 1495.0, 1509.0, 1514.0, 1533.01, 1569.0, 1986.0, 2217.0, 2227.0, 2278.0, 2299.0, 2372.0, 2647.0 (Exhibit 10.18 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.19 - Letter Agreement between Colorado Interstate Gas Company and Enron Oil & Gas Marketing, Inc. dated November 1, 1990 (Exhibit 10.18 to the Company's Annual Report on Form 10-K for the year ended December 31, 1990). 10.23 - Gas Purchase Agreement between Enron Oil & Gas Company and Enron Oil & Gas Marketing, Inc. dated August 22, 1989 (Exhibit 10.41 to Form S-1). 10.24 - Gas Purchase Agreement between Enron Oil & Gas Company and Enron Oil & Gas Marketing, Inc. dated August 22, 1989 (Exhibit 10.42 to Form S-1). 10.25 - Enron Corp. 1991 Stock Plan (Exhibit 10.08 to Enron Corp. Annual Report on Form 10-K for the year ended December 31, 1991). 10.26 - Enron Corp. 1988 Deferral Plan (Exhibit 10.49 to Form S-1). </TABLE> E-2
75 <TABLE> <CAPTION> EXHIBIT NUMBER DESCRIPTION -------------- ----------- <C> <S> <C> 10.28 - Enron Executive Supplemental Survivor Benefits Plan Effective January 1, 1987 (Exhibit 10.51 to Form S-1). 10.30 - Credit Agreement between Enron Corp. and Enron Oil & Gas Company dated September 29, 1995 (Exhibit 10.30 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). 10.31 - Credit Agreement between Enron Oil & Gas Company and Enron Corp. dated September 29, 1995 (Exhibit 10.31 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). 10.34(a) - Enron Oil & Gas Company 1992 Stock Plan (As Amended and Restated effective December 14, 1994) (incorporated by reference to Exhibit A to the Company's Proxy Statement, dated March 27, 1995, with respect to the Company's 1995 Annual Meeting of Shareholders). 10.34(b) - Amendment to Enron Oil & Gas Company 1992 Stock Plan (As Amended and Restated Effective December 14, 1994) (Exhibit 10.34(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). 10.34(c) - Second Amendment to Enron Oil & Gas Company 1992 Stock Plan (As Amended and Restated Effective December 14, 1994 (Exhibit 10.34(c) to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). 10.35 - Enron Corp. 1992 Deferral Plan (Exhibit 10.41 to the Company's Annual Report on Form 10-K for the year ended December 31, 1991). 10.36(a) - Conveyance of Production Payment, dated September 25, 1992, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.34 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992). 10.36(b) - First Amendment to Conveyance of Production Payment, dated effective April 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.36(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.36(c) - Second Amendment to Conveyance of Production Payment, dated effective July 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.36(c) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.36(d) - Third Amendment to Conveyance of Production Payment, dated effective October 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.36(d) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.37(a) - Hydrocarbon Exchange Agreement dated September 25, 1992, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.35 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992). 10.37(b) - Amendment to Hydrocarbon Exchange Agreement dated effective as of January 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.37(c) - First Amendment to Hydrocarbon Exchange Agreement dated effective as of April 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37(c) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). </TABLE> E-3
76 <TABLE> <CAPTION> EXHIBIT NUMBER DESCRIPTION -------------- ----------- <C> <S> <C> 10.37(d) - Second Amendment to Hydrocarbon Exchange Agreement dated effective as of July 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37(d) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.37(e) - Amendment to Hydrocarbon Exchange Agreement dated effective as of August 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37(e) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.37(f) - Fourth Amendment to Hydrocarbon Exchange Agreement, dated effective October 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.38 - Purchase and Sale Agreement, dated September 25, 1992, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.36 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992). 10.39(a) - Production and Delivery Agreement, dated September 25, 1992, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992). 10.39(b) - First Amendment to Production and Delivery Agreement, dated effective April 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.39(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.39(c) - Second Amendment to Production and Delivery Agreement, dated effective July 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.39(c) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.39(d) - Third Amendment to Production and Delivery Agreement, dated effective October 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.39(d) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.57(a) - Letter Agreement relating to Natural Gas Swap Transactions, dated March 31, 1995, among Enron Oil & Gas Company, Enron Corp. and Enron Capital & Trade Resources Corp (Exhibit 10.57(a) to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). 10.57(b) - Amendment to Natural Gas Swap Transactions Letter Agreement, dated March 31, 1995, among Enron Oil & Gas Company, Enron Corp. and Enron Capital & Trade Resources Corp (Exhibit 10.57(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). 10.58 - Confirmation Letter (revised due to adjustments to the attached Payment Schedule), dated March 31, 1995, between Enron Oil & Gas Company and Enron Capital & Trade Resources Corp. (ECT Transaction Reference No. 15198.00) (Exhibit 10.58 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). 10.59 - Confirmation Letter (revised due to Price Change for 1998 and adjustment to the attached Payment Schedule), dated March 31, 1995, between Enron Oil & Gas Company and Enron Capital & Trade Resources Corp. (ECT Transaction Reference No. 15198.01) (Exhibit 10.59 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). </TABLE> E-4
77 <TABLE> <CAPTION> EXHIBIT NUMBER DESCRIPTION -------------- ----------- <C> <S> <C> 10.60 - Services Agreement, dated January 1, 1997, between Enron Corp. and Enron Oil & Gas Company (Exhibit 10.60 to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). 10.61 - Equity Participation and Business Opportunity Agreement, dated December 9, 1997, between Enron Oil & Gas Company and Enron Corp. (Exhibit 10 to Form S-3 Registration Statement No. 333-44785, filed January 23, 1998). 10.62 - Stock Restriction and Registration Rights Agreement, dated December 9, 1997, between Enron Corp. and Enron Oil & Gas Company (Exhibit 10.62 to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). 10.63(a) - Enron Oil & Gas Company 1996 Deferral Plan (Exhibit 10.63(a) to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). 10.63(b) - First Amendment to Enron Oil & Gas Company 1996 Deferral Plan, dated effective as of December 9, 1997 (Exhibit 10.63(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). *10.63(c) - Second Amendment to Enron Oil & Gas Company 1996 Deferral Plan, dated effective as of December 8, 1998. 10.64 - Executive Employment Agreement between Enron Oil & Gas Company and Mark G. Papa, effective as of November 1, 1997 (Exhibit 10.64 to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). *10.65 - Executive Employment Agreement between Enron Oil & Gas Company and Edmund P. Segner, III, effective as of September 1, 1998. *10.66 - Executive Employment Agreement between Enron Oil & Gas Company and Dennis M. Ulak, effective as of September 1, 1998. *10.67 - Executive Employment Agreement between Enron Oil & Gas Company and Jeffery B. Sherrick, effective as of September 1, 1998. *21 - List of subsidiaries. *23.1 - Consent of DeGolyer and MacNaughton. *23.2 - Opinion of DeGolyer and MacNaughton dated January 11, 1999. *23.3 - Consent of Arthur Andersen LLP. *24 - Powers of Attorney. *27 - Financial Data Schedule. </TABLE> E-5
78 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 18th day of March, 1999. ENRON OIL & GAS COMPANY (Registrant) By /s/ WALTER C. WILSON ------------------------------------ (Walter C. Wilson) Senior Vice President and Chief Financial Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of registrant and in the capacities with Enron Oil & Gas Company indicated and on the 18th day of March, 1999. <TABLE> <CAPTION> SIGNATURE TITLE --------- ----- <C> <S> /s/ MARK G. PAPA President and Chief Executive Officer - ----------------------------------------------------- and Director (Principal Executive (Mark G. Papa) Officer) /s/ WALTER C. WILSON Senior Vice President and Chief - ----------------------------------------------------- Financial Officer (Principal Financial (Walter C. Wilson) and Principal Accounting Officer) FORREST E. HOGLUND * Chairman of the Board and Director - ----------------------------------------------------- (Forrest E. Hoglund) FRED C. ACKMAN * Director - ----------------------------------------------------- (Fred C. Ackman) RICHARD A. CAUSEY * Director - ----------------------------------------------------- (Richard A. Causey) JAMES V. DERRICK, JR * Director - ----------------------------------------------------- (James V. Derrick, Jr.) JOHN H. DUNCAN * Director - ----------------------------------------------------- (John H. Duncan) KEN L. HARRISON * Director - ----------------------------------------------------- (Ken L. Harrison) KENNETH L. LAY * Director - ----------------------------------------------------- (Kenneth L. Lay) EDWARD RANDALL, III * Director - ----------------------------------------------------- (Edward Randall, III) JEFFREY K. SKILLING * Director - ----------------------------------------------------- (Jeffrey K. Skilling) FRANK G. WISNER * Director - ----------------------------------------------------- (Frank G. Wisner) *By /s/ ANGUS H. DAVIS -------------------------------------------------- (Angus H. Davis) (Attorney-in-fact for persons indicated) </TABLE>
79 EXHIBIT INDEX Exhibits not incorporated herein by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated herein by reference to the Company's Form S-1 Registration Statement, Registration No. 33-30678, filed on August 24, 1989 ("Form S-1"), or as otherwise indicated. <TABLE> <CAPTION> EXHIBIT NUMBER DESCRIPTION -------------- ----------- <C> <S> 3.1(a) - Restated Certificate of Incorporation of Enron Oil & Gas Company (Exhibit 3.1 to Form S-1). 3.1(b) - Certificate of Amendment of Restated Certificate of Incorporation of Enron Oil & Gas Company (Exhibit 4.1(b) to Form S-8 Registration Statement No. 33-52201, filed February 8, 1994). 3.1(c) - Certificate of Amendment of Restated Certificate of Incorporation of Enron Oil & Gas Company (Exhibit 4.1(c) to Form S-8 Registration Statement No. 33-58103, filed March 15, 1995). 3.1(d) - Certificate of Amendment of Restated Certificate of Incorporation of Enron Oil & Gas Company, dated June 11, 1996 (Exhibit 3(d) to Form S-3 Registration Statement No. 333-09919, filed August 9, 1996). 3.1(e) - Certificate of Amendment of Restated Certificate of Incorporation of Enron Oil & Gas Company, dated May 7, 1997 (Exhibit 3(e) to Form S-3 Registration Statement No. 333-44785, filed January 23, 1998). *3.2 - By-laws of Enron Oil & Gas Company dated August 23, 1989, as amended December 12, 1990, February 8, 1994, January 19, 1996, February 13, 1997 and May 5, 1998. 3.3 - Specimen of Certificate evidencing the Common Stock (Exhibit 3.3 to Form S-1). 4.3(a) - Amended and Restated Enron Oil & Gas Company 1994 Stock Plan (Exhibit 4.3 to Form S-8 Registration Statement No. 33-58103, filed March 15, 1995). 4.3(b) - Amendment to Amended and Restated Enron Oil & Gas Company 1994 Stock Plan, dated effective as of December 12, 1995 (Exhibit 4.3(a) to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). 4.3(c) - Amendment to Amended and Restated Enron Oil & Gas Company 1994 Stock Plan, dated effective as of December 10, 1996 (Exhibit 4.3(a) to Form S-8 Registration Statement No. 333-20841, filed January 31, 1997). 4.3(d) - Third Amendment to Amended and Restated Enron Oil & Gas Company 1994 Stock Plan, dated effective as of December 9, 1997 (Exhibit 4.3(d) to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). *4.3(e) - Fourth Amendment to Amended and Restated Enron Oil & Gas Company 1994 Stock Plan, dated effective as of May 5, 1998. *4.3(f) - Fifth Amendment to Amended and Restated Enron Oil & Gas Company 1994 Stock Plan, dated effective as of December 8, 1998. 10.2(a) - Stock Restriction and Registration Agreement dated as of August 23, 1989 (Exhibit 10.2 to Form S-1). 10.2(b) - Amendment to Stock Restriction and Registration Agreement, dated December 9, 1997, between Enron Oil & Gas Company and Enron Corp. (Exhibit 10.2(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). *10.3 - Tax Allocation Agreement, entered into effective as of Deconsolidation Date between Enron Corp., Enron Oil & Gas Company, and the subsidiaries of Enron Oil & Gas Company listed therein as additional parties. </TABLE>
80 <TABLE> <CAPTION> EXHIBIT NUMBER DESCRIPTION -------------- ----------- <C> <S> 10.9(a) - Employment Agreement between Enron Oil & Gas Company and Forrest Hoglund, dated as of September 1, 1987, as amended (Exhibit 10.19 to Form S-1), and Second and Third Amendments to Employment Agreement dated June 30, 1989 and February 14, 1992, respectively (Exhibit 10.10 to Form S-1 Registration Statement No. 33-50462, filed August 5, 1992). 10.9(b) - 4th Amendment to Employment Agreement dated December 14, 1994, among Enron Corp., Enron Oil & Gas Company and Forrest Hoglund (Exhibit 10.9(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). *10.9(c) - Fifth Amendment to Employment Agreement entered into September 8, 1998, and effective as of September 1, 1998, among Enron Corp., Enron Oil & Gas Company and Forrest E. Hoglund. 10.14(a) - Enron Oil & Gas Company 1993 Nonemployee Directors' Stock Option Plan (Exhibit 10.14 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992). 10.14(b) - First Amendment to Enron Oil & Gas Company 1993 Nonemployee Directors' Stock Option Plan (Exhibit 10.14(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1996). 10.16 - Interest Rate and Currency Exchange Agreement, dated as of June 1, 1991, between Enron Risk Management Services Corp. and Enron Oil & Gas Marketing, Inc. (Exhibit 10.17 to the Company's Annual Report on Form 10-K for the year ended December 31, 1991), Confirmation dated June 14, 1992 (Exhibit 10.17 to Form S-1 Registration Statement, No. 33-50462, filed August 5, 1992) and Confirmations dated March 25, 1991, April 25, 1991, and September 23, 1992 (assigned to Enron Risk Management Services Corp. by Enron Finance Corp. pursuant to an Assignment and Assumption Agreement, dated as of November 1, 1993, by and between Enron Finance Corp., Enron Risk Management Services Corp. and Enron Oil & Gas Marketing, Inc.). (Exhibit 10.16 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.17 - Assignment and Assumption Agreement, dated as of November 1, 1993, by and between Enron Oil & Gas Marketing, Inc., Enron Oil & Gas Company and Enron Risk Management Services Corp. (Exhibit 10.17 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.18 - ISDA Master Agreement, dated as of November 1, 1993, between Enron Oil & Gas Company and Enron Risk Management Services Corp., and Confirmation Nos. 1268.0, 1286.0, 1291.0, 1292.0, 1304.0, 1305.0, 1321.0, 1335.0, 1338.0, 1370.0, 1471.0, 1485.0, 1486.0, 1494.0, 1495.0, 1509.0, 1514.0, 1533.01, 1569.0, 1986.0, 2217.0, 2227.0, 2278.0, 2299.0, 2372.0, 2647.0 (Exhibit 10.18 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.19 - Letter Agreement between Colorado Interstate Gas Company and Enron Oil & Gas Marketing, Inc. dated November 1, 1990 (Exhibit 10.18 to the Company's Annual Report on Form 10-K for the year ended December 31, 1990). 10.23 - Gas Purchase Agreement between Enron Oil & Gas Company and Enron Oil & Gas Marketing, Inc. dated August 22, 1989 (Exhibit 10.41 to Form S-1). 10.24 - Gas Purchase Agreement between Enron Oil & Gas Company and Enron Oil & Gas Marketing, Inc. dated August 22, 1989 (Exhibit 10.42 to Form S-1). 10.25 - Enron Corp. 1991 Stock Plan (Exhibit 10.08 to Enron Corp. Annual Report on Form 10-K for the year ended December 31, 1991). 10.26 - Enron Corp. 1988 Deferral Plan (Exhibit 10.49 to Form S-1). </TABLE>
81 <TABLE> <CAPTION> EXHIBIT NUMBER DESCRIPTION -------------- ----------- <C> <S> 10.28 - Enron Executive Supplemental Survivor Benefits Plan Effective January 1, 1987 (Exhibit 10.51 to Form S-1). 10.30 - Credit Agreement between Enron Corp. and Enron Oil & Gas Company dated September 29, 1995 (Exhibit 10.30 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). 10.31 - Credit Agreement between Enron Oil & Gas Company and Enron Corp. dated September 29, 1995 (Exhibit 10.31 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). 10.34(a) - Enron Oil & Gas Company 1992 Stock Plan (As Amended and Restated effective December 14, 1994) (incorporated by reference to Exhibit A to the Company's Proxy Statement, dated March 27, 1995, with respect to the Company's 1995 Annual Meeting of Shareholders). 10.34(b) - Amendment to Enron Oil & Gas Company 1992 Stock Plan (As Amended and Restated Effective December 14, 1994) (Exhibit 10.34(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). 10.34(c) - Second Amendment to Enron Oil & Gas Company 1992 Stock Plan (As Amended and Restated Effective December 14, 1994 (Exhibit 10.34(c) to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). 10.35 - Enron Corp. 1992 Deferral Plan (Exhibit 10.41 to the Company's Annual Report on Form 10-K for the year ended December 31, 1991). 10.36(a) - Conveyance of Production Payment, dated September 25, 1992, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.34 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992). 10.36(b) - First Amendment to Conveyance of Production Payment, dated effective April 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.36(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.36(c) - Second Amendment to Conveyance of Production Payment, dated effective July 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.36(c) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.36(d) - Third Amendment to Conveyance of Production Payment, dated effective October 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.36(d) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.37(a) - Hydrocarbon Exchange Agreement dated September 25, 1992, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.35 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992). 10.37(b) - Amendment to Hydrocarbon Exchange Agreement dated effective as of January 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.37(c) - First Amendment to Hydrocarbon Exchange Agreement dated effective as of April 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37(c) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). </TABLE>
82 <TABLE> <CAPTION> EXHIBIT NUMBER DESCRIPTION -------------- ----------- <C> <S> 10.37(d) - Second Amendment to Hydrocarbon Exchange Agreement dated effective as of July 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37(d) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.37(e) - Amendment to Hydrocarbon Exchange Agreement dated effective as of August 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37(e) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.37(f) - Fourth Amendment to Hydrocarbon Exchange Agreement, dated effective October 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.38 - Purchase and Sale Agreement, dated September 25, 1992, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.36 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992). 10.39(a) - Production and Delivery Agreement, dated September 25, 1992, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992). 10.39(b) - First Amendment to Production and Delivery Agreement, dated effective April 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.39(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.39(c) - Second Amendment to Production and Delivery Agreement, dated effective July 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.39(c) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.39(d) - Third Amendment to Production and Delivery Agreement, dated effective October 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.39(d) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.57(a) - Letter Agreement relating to Natural Gas Swap Transactions, dated March 31, 1995, among Enron Oil & Gas Company, Enron Corp. and Enron Capital & Trade Resources Corp (Exhibit 10.57(a) to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). 10.57(b) - Amendment to Natural Gas Swap Transactions Letter Agreement, dated March 31, 1995, among Enron Oil & Gas Company, Enron Corp. and Enron Capital & Trade Resources Corp (Exhibit 10.57(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). 10.58 - Confirmation Letter (revised due to adjustments to the attached Payment Schedule), dated March 31, 1995, between Enron Oil & Gas Company and Enron Capital & Trade Resources Corp. (ECT Transaction Reference No. 15198.00) (Exhibit 10.58 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). 10.59 - Confirmation Letter (revised due to Price Change for 1998 and adjustment to the attached Payment Schedule), dated March 31, 1995, between Enron Oil & Gas Company and Enron Capital & Trade Resources Corp. (ECT Transaction Reference No. 15198.01) (Exhibit 10.59 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). </TABLE>
83 <TABLE> <CAPTION> EXHIBIT NUMBER DESCRIPTION -------------- ----------- <S> <C> 10.60 - Services Agreement, dated January 1, 1997, between Enron Corp. and Enron Oil & Gas Company (Exhibit 10.60 to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). 10.61 - Equity Participation and Business Opportunity Agreement, dated December 9, 1997, between Enron Oil & Gas Company and Enron Corp. (Exhibit 10 to Form S-3 Registration Statement No. 333-44785, filed January 23, 1998). 10.62 - Stock Restriction and Registration Rights Agreement, dated December 9, 1997, between Enron Corp. and Enron Oil & Gas Company (Exhibit 10.62 to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). 10.63(a) - Enron Oil & Gas Company 1996 Deferral Plan (Exhibit 10.63(a) to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). 10.63(b) - First Amendment to Enron Oil & Gas Company 1996 Deferral Plan, dated effective as of December 9, 1997 (Exhibit 10.63(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). *10.63(c) - Second Amendment to Enron Oil & Gas Company 1996 Deferral Plan, dated effective as of December 8, 1998. 10.64 - Executive Employment Agreement between Enron Oil & Gas Company and Mark G. Papa, effective as of November 1, 1997 (Exhibit 10.64 to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). *10.65 - Executive Employment Agreement between Enron Oil & Gas Company and Edmund P. Segner, III, effective as of September 1, 1998. *10.66 - Executive Employment Agreement between Enron Oil & Gas Company and Dennis M. Ulak, effective as of September 1, 1998. *10.67 - Executive Employment Agreement between Enron Oil & Gas Company and Jeffery B. Sherrick, effective as of September 1, 1998. *21 - List of subsidiaries. *23.1 - Consent of DeGolyer and MacNaughton. *23.2 - Opinion of DeGolyer and MacNaughton dated January 11, 1999. *23.3 - Consent of Arthur Andersen LLP. *24 - Powers of Attorney. *27 - Financial Data Schedule. </TABLE>