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, 1997 [ ] 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> <CAPTION> NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED ------------------- --------------------- <S> <C> 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. [X]. 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 27, 1998 was $1,450,296,850. As of March 1, 1998, there were 154,762,377 shares of the registrant's Common Stock, $.01 par value, outstanding. DOCUMENTS INCORPORATED BY REFERENCE. Certain portions of the registrant's definitive Proxy Statement for the May 5, 1998 Annual Meeting of Shareholders ("Proxy Statement") are incorporated in Part III by reference. ================================================================================
2 TABLE OF CONTENTS PART I <TABLE> <CAPTION> PAGE ---- <S> <C> <C> Item 1. Business General..................................................... 1 Business Segments........................................... 2 Exploration and Production.................................. 2 Marketing................................................... 5 Wellhead Volumes and Prices, and Lease and Well Expenses.... 7 Competition................................................. 8 Regulation.................................................. 8 Relationship Between the Company and Enron Corp............. 11 Other Matters............................................... 15 Current Executive Officers of the Registrant................ 17 Item 2. Properties Oil and Gas Exploration and Production Properties and Reserves.................................................. 18 Item 3. Legal Proceedings........................................... 20 Item 4. Submission of Matters to a Vote of Security Holders......... 21 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 8. Financial Statements and Supplementary Data................. 29 Item 9. Disagreements on Accounting and Financial Disclosure........ 29 PART III Item 10. Directors and Executive Officers of the Registrant.......... 29 Item 11. Executive Compensation...................................... 29 Item 12. Security Ownership of Certain Beneficial Owners and Management................................................ 29 Item 13. Certain Relationships and Related Transactions.............. 30 PART IV Item 14. Financial Statements and Financial Statement Schedule, Exhibits and Reports on Form 8-K.......................... 30 </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, 1997, the Company's estimated net proved natural gas reserves were 4,001 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 78 million barrels ("MMBbl"). (See "Supplemental Information to Consolidated Financial Statements"). At such date, approximately 67% of the Company's reserves (on a natural gas equivalent basis) was located in the United States, 10% in Canada, 8% in Trinidad and 15% in India. As of December 31, 1997, the Company employed approximately 825 persons. 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 1997 drilling activity toward natural gas deliverability in addition to natural gas reserve enhancement and crude oil exploitation in the United States in response to the higher United States natural gas prices in recent periods. The Company also is focusing 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, 1997, Enron Corp. owned 55% of the outstanding shares of the common stock of the Company. (See "Relationship Between the Company and Enron Corp."). 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 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. 1
4 BUSINESS SEGMENTS The Company's operations are all natural gas and crude oil exploration and production related. Accordingly, such operations are classified as one business segment. 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 82% of the Company's United States reserves (on a natural gas equivalent basis) and 79% of the Company's United States net natural gas deliverability as of December 31, 1997 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, 1997, 94% 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 6% 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 263,000 net acres under lease directly within field limits. The Company operates approximately 780 oil and natural gas wells in this area in which it owns an 85% average working interest. Deliveries from the area net to the Company averaged 114 million cubic feet ("MMcf") per day of natural gas and 3.7 thousand barrels ("MBbl") per day of crude oil, condensate, and natural gas liquids in 1997. At December 31, 1997, natural gas deliverability net to the Company was approximately 130 MMcf per day. The current principal producing intervals are the Frontier and Mesaverde formations. The Frontier formation, which occurs at 6,500 to 10,000 feet, contains approximately 62% of the Company's Big Piney proved developed reserves. The Company drilled 87 wells in the Big Piney area in 1997 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 formation located under acreage leased by the Company and held by production in the Big Piney area. The Company is actively pursuing the consummation of a market or markets from several different potential sources to facilitate realizing the value of these reserves. 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 Starr counties. During 1997, the Company acquired an interest in a significant Wilcox Trend property in Duval County. Net production from the acquired property as of December 31, 1997 was 15 MMcf of natural gas equivalent per day. The Company now operates approximately 427 wells in the South Texas area. Production is primarily from the Upper Wilcox and Lobo sands at depths ranging from 5,000 to 16,000 feet. The Company has approximately 240,000 net leasehold acres and more than 40,000 net mineral fee acres in this area. Natural gas deliveries net to the Company averaged approximately 182 MMcf per day in 1997. At December 31, 1997, 2
5 natural gas deliverability from this area net to the Company was approximately 180 MMcf per day. The Company drilled 65 wells in the South Texas area in 1997 and participated in sizable 3-D seismic and leasehold acquisition efforts during the year. 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 field, 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 77% working interest in this area. The Company drilled 30 wells in the Carthage field in 1997 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 22 wells and holds a 100% working interest in the acreage. Further drilling is planned for 1998. The Company drilled 3 wells in the Stowell field in 1997 and expects to expand the program substantially in 1998. At December 31, 1997, deliverability from the East Texas area was approximately 50 MMcf per day of natural gas with 1.9 MBbl per day of crude oil, condensate and natural gas liquids both net to the Company. The Company holds 60,000 net acres in southern Anderson County in the East Texas Jurassic reef play and is presently shooting an 83.5 square mile 3-D seismic survey to define drilling locations. Offshore Gulf of Mexico Area. During 1997, the Company participated in two lease sales offering leases in the Gulf of Mexico and acquired approximately 81,200 net acres (17 leases). As a result of the lease sale activity, the Company continued to build its deepwater portfolio by acquiring eight deepwater (greater than 600 feet) tracts in 1997 to add to the seven tracts acquired in 1996. At December 31, 1997, the Company held an interest in 192 blocks in the Offshore Gulf of Mexico area totaling approximately 546,000 net acres. Of the 192 blocks, 141 are operated by the Company. These interests are located predominantly in federal waters offshore Texas and Louisiana. Natural gas deliveries from this area averaged 111 MMcf per day during 1997 net to the Company. A substantial portion of such deliveries was from interests in the Matagorda trend with significant volumes also coming from the Mustang Island area. Deliverability from the offshore Gulf of Mexico area at December 31, 1997 was approximately 110 MMcf per day net to the Company sourced principally as noted above. During 1997, the Company participated in the drilling of 10 wells (5.2 net wells) in the Gulf of Mexico, a decrease in drilling activity of approximately 50% as compared to 1996 and 1995. In 1998, the Company anticipates participating in the drilling of 15 to 20 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 51 natural gas wells during 1997. The Company holds approximately 63,000 net acres and now operates approximately 325 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, 1997, natural gas deliverability net to the Company was approximately 35 MMcf per day. The Company plans an aggressive program on several new prospects in 1998, including the potential for some horizontal drilling. Sand Tank Area. The Sand Tank area located in Eddy County, New Mexico produces from the Chester, Morrow, and Atoka formations. In 1997, the Company acquired 42 square miles of 3-D seismic and drilled 13 wells, increasing natural gas deliverability to approximately 20 MMcf per day at year end. The Company holds 12,000 net acres and has an average working interest of approximately 57%. Several wells are planned in 1998 for this stacked-pay area. Pitchfork Ranch Area. The Pitchfork Ranch area located in Lea County, New Mexico, produces primarily from the Bone Spring, Atoka and Morrow formations. In 1997, deliveries net to the Company averaged 21 MMcf per day of natural gas and approximately 2 MBbl per day of crude oil, condensate and natural gas liquids. At December 31, 1997, deliverability net to the Company was approximately 15 MMcf per day of natural gas and 1.9 MBbl per day of crude oil, condensate and natural gas liquids. The Company holds approximately 28,000 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 for several years. 3
6 Vernal Area. In the Vernal area, located primarily in Uintah County, Utah, the Company operates approximately 245 producing wells and presently controls approximately 74,000 net acres. In 1997, natural gas deliveries net to the Company from the Vernal area averaged 15 MMcf per day. Deliverability at December 31, 1997, was approximately 16 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 for several years. Canada. The Company is engaged in the exploration for and the development, production and marketing of natural gas and crude oil and the operation of natural gas processing plants in Western Canada, principally in the provinces of Alberta, Saskatchewan, and Manitoba. The Company conducts operations from offices in Calgary, and produces natural gas from seven major areas and crude oil from four major areas. Additional interests were acquired in the Blackfoot producing area through two separate transactions in July 1997 and September 1997. Net production from the acquired properties at December 31, 1997 was 13 MMcf of natural gas equivalent per day. The Sandhills area in southwestern Saskatchewan is the largest single producing area in Canada. In 1997, 93 wells were drilled in the area resulting in deliverability of approximately 40 MMcf per day net to the Company at December 31, 1997. Total Canadian natural gas deliverability net to the Company at December 31, 1997 was approximately 100 MMcf per day, and the Company held approximately 490,000 net undeveloped acres in Canada. The Company expects to maintain an active drilling program 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 Oil Bird 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 1997, deliveries net to the Company averaged 113 MMcf per day of natural gas and 3.4 MBbl per day of crude oil and condensate. At December 31, 1997, the Company held approximately 168,000 net undeveloped acres in Trinidad. In 1995, the Company was awarded the right to develop the modified U(a) block adjacent to the SECC Block. A production sharing contract was signed with the Government of Trinidad and Tobago in 1996. A 3-D seismic data gathering project has been completed and is being evaluated. Initial drilling is planned to occur during 1998. 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, 1997, production, net to the Company, from Tapti was 48 MMcf per day. The 106,000 acre Panna Block and the 192,000 acre Mukta Block are partially developed with 29 wells producing from six production platforms located in the Panna and Mukta fields. The fields were producing approximately 4.3 MBbl per day of crude oil net to the Company as of December 31, 1997. Natural gas sales began from the Panna field during the first quarter of 1998. 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 4
7 government of Venezuela and other participants associated with a concession awarded in the Gulf of Paria East. The Company holds an initial 90 percent working interest in the joint venture and acts as operator. A 3-D seismic data project is currently underway and initial drilling is anticipated in 1998. 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 percent 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 areas of proven production. Further commitments, if any, would arise from entering into the development period as specified in the contract. 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. In early 1995, the Company, an Enron Corp. affiliate and the Qatar General Petroleum Corporation signed a nonbinding letter of intent concerning the possible development of a liquefied natural gas project for natural gas to be produced from a block within the North Dome Field. The Company and the Enron Corp. affiliate may jointly hold up to a 35% equity interest in the project. The Company has also completed the extension and enhancement of an existing Memorandum of Understanding with Uzbekneftegaz covering the pursuit of joint development and marketing opportunities for proven hydrocarbon reserves in eleven fields in the Surhandarya and Bukhara regions of Uzbekistan. 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, Venezuela and Bangladesh. (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 projects in Qatar, Uzbekistan and Mozambique.) 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 to be 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 15% 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 10% of the Company's wellhead crude oil and condensate production is currently being sold to affiliated companies. 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 5
8 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. (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 $7 million, respectively, with offsetting decreases in 1998 and 1999 versus that anticipated under the Cogen Contracts. 6
9 WELLHEAD VOLUMES AND PRICES, AND LEASE AND WELL EXPENSES The following table sets forth certain information regarding the Company's wellhead volumes of and average prices for natural gas per thousand cubic feet ("Mcf"), crude oil and condensate, and natural gas liquids per barrel ("Bbl"), and average lease and well expenses per thousand cubic feet equivalent ("Mcfe" - natural gas equivalents are determined using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of crude oil, condensate or natural gas liquids) delivered during each of the three years in the period ended December 31, 1997: <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, -------------------------- 1997 1996 1995 ------ ------ ------ <S> <C> <C> <C> VOLUMES (PER DAY) Natural Gas (MMcf) United States(1)....................................... 657 608 560 Canada................................................. 101 98 76 Trinidad............................................... 113 124 107 India.................................................. 18 - - ------ ------ ------ Total............................................. 889 830 743 ====== ====== ====== Crude Oil and Condensate (MBbl) United States.......................................... 11.7 9.2 9.1 Canada................................................. 2.5 2.4 2.4 Trinidad............................................... 3.4 5.2 5.1 India.................................................. 2.3 2.8 2.5 ------ ------ ------ Total............................................. 19.9 19.6 19.1 ====== ====== ====== Natural Gas Liquids (MBbl) United States.......................................... 2.6 1.3 1.0 Canada................................................. 1.3 1.2 .4 ------ ------ ------ Total............................................. 3.9 2.5 1.4 ====== ====== ====== AVERAGE PRICES Natural Gas ($/Mcf) United States(2)....................................... $ 2.32 $ 2.04 $ 1.39 Canada................................................. 1.43 1.15 .97 Trinidad............................................... 1.05 1.00 .97 India.................................................. 2.79 - - Composite......................................... 2.07 1.78 1.29 Crude Oil and Condensate ($/Bbl) United States.......................................... $19.81 $21.88 $17.32 Canada................................................. 17.16 18.01 16.22 Trinidad............................................... 18.68 19.76 16.07 India.................................................. 20.05 20.17 16.81 Composite......................................... 19.30 20.60 16.78 Natural Gas Liquids ($/Bbl) United States.......................................... $12.76 $14.67 $11.88 Canada................................................. 8.94 9.14 9.74 Composite......................................... 11.54 11.99 11.31 LEASE AND WELL EXPENSES ($/MCFE) United States.......................................... $ .23 $ .19 $ .19 Canada................................................. .39 .34 .35 Trinidad............................................... .16 .16 .15 India.................................................. .64 .99 1.25(3) Composite......................................... .26 .22 .22 </TABLE> - --------------- (1) Includes 48 MMcf per day in 1997, 1996 and 1995 delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended. (2) Includes an average equivalent wellhead value of $1.73 per Mcf in 1997, $1.17 per Mcf in 1996, and $.80 per Mcf in 1995 for the volumes described in note (1), net of transportation costs. (3) Includes certain nonrecurring startup 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). For such offshore operations, lessees must obtain MMS approval for exploration, development, and production plans prior to the commencement of such operations. The MMS has promulgated regulations requiring offshore production facilities located on the OCS to meet stringent engineering and construction specifications. The MMS also has proposed additional safety-related regulations concerning the design and operating procedures for OCS production platforms and pipelines, but these proposed regulations were withdrawn pending further discussions among interested federal agencies. With respect to conservation, the MMS has regulations restricting the flaring or venting of natural gas and has proposed to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization. The MMS has also promulgated other regulations governing the plugging and abandonment of wells located offshore 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 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. In April 1997, after two years of study, the MMS withdrew proposed changes to the way it values natural gas for royalty payments. These proposed changes would have established an alternative market-based method 8
11 to calculate royalties on certain natural gas sold to affiliates or pursuant to non-arm's length sales contracts. Informal discussions among the MMS and industry officials are continuing, although it is uncertain whether, and what changes may be proposed regarding gas royalty valuation. In addition, MMS has recently announced its intention to issue a proposed rule that would require all but the smallest producers to be capable of reporting production information electronically by the end of 1998. The MMS has 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. 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. Consequently, sales of the Company's natural gas currently may be made at market prices, subject to applicable contract provisions. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and nondiscriminatory basis. These efforts have significantly altered the marketing and pricing of natural gas. Commencing in April 1992, the FERC issued Order Nos. 636, 636A and 636B ("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 previously existing city-gate sales service, and to separately state the rates for each unbundled service. Under Order No. 636, unbundled pipeline sales can be made only in the production areas. The purpose of Order No. 636 is to further enhance competition in the natural gas industry by assuring the comparability of pipeline sales service and services offered by a pipeline's competitors. The FERC issued final orders accepting most pipelines' Order No. 636 compliance filings, and has commenced a series of one-year reviews of individual pipeline implementations of Order No. 636. The federal appellate courts have largely affirmed the significant features of Order No. 636 and numerous related orders pertaining to the individual pipelines. Order No. 636 does not directly regulate the Company's activities, but has had and will have an indirect effect because of its broad scope. Because further review of certain of these orders is still possible, various appeals remain pending and the FERC continues to review and modify its open access regulations, the outcome of such proceedings and their ultimate impact on the Company's business is difficult to predict with precision. In many instances, however, Order No. 636 has substantially reduced or brought to an end interstate pipelines' traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. Order No. 636 has also substantially increased competition in natural gas markets, even though there remains significant uncertainty with respect to the marketing and transportation of natural gas. 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. In July 1994, the FERC eliminated a regulation that had rendered virtually all sales of natural gas by pipeline affiliates, such as the Company, to be deregulated first sales. As a result, only sales by the Company of its own production now qualify for this status. All other sales of natural gas by the Company, such as those of natural gas purchased from third parties, are now jurisdictional sales subject to a blanket sales certificate issued by the FERC under the NGA. The Company does not anticipate this change will have any significant current adverse effects in light of the flexible terms and conditions of the existing blanket certificate. Such sales are subject to the future possibility of greater federal oversight, however, including the possibility the FERC might prospectively impose more restrictive conditions on such sales. 9
12 The FERC has extended indefinitely its regulations (Order No. 497 regulations) governing relationships between interstate pipelines and their marketing affiliates, subject to revisions to delete an out-of-date standard and revise certain reporting and record keeping requirements. Among other matters, these new rules require pipelines to post on their electronic bulletin boards, within 24 hours of gas flow, information concerning discounted transportation provided to marketing affiliates to enable competing marketers to request comparable discounts. Order No. 497 does not directly regulate the Company's activities, although a substantial portion of the Company's natural gas production is sold to or transported by interstate pipeline affiliates which are subject to the Order. The Company's activities may therefore be indirectly affected by these regulations. 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 State of Oklahoma in 1995 enacted legislation that essentially requires gatherers to provide open access, non-discriminatory service. In addition, the FERC has reiterated that, except in situations in which the gatherer acts in concert with an interstate pipeline affiliate to frustrate the FERC's transportation policies, it does not have jurisdiction over natural gas gathering facilities and services and that such facilities and services are properly regulated by state authorities. This FERC action may further encourage regulatory scrutiny of natural gas gathering by state agencies. Indeed, the Texas Railroad Commission recently 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. In addition, the FERC has approved several transfers by interstate pipelines, including certain of the Company's pipeline affiliates, of gathering facilities to unregulated independent or affiliated gathering companies. This could increase competition among gatherers in the affected areas. Certain of the FERC's orders delineating its new gathering policy are subject to pending court appeals. 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 FERC has recently announced its intention to reexamine certain of its transportation-related policies, including the manner in which interstate pipelines release transportation capacity under Order No. 636, and has announced new policies concerning the use of alternative, non-cost based methods for setting rates for interstate natural gas transmission. A number of pipelines have obtained FERC authorization to charge negotiated rates as one such alternative. Additionally, the FERC has recently requested comments on the financial outlook of the gas pipeline industry, including, among other matters, whether the FERC's current ratemaking policies are suitable in the current industry environment. Finally, the FERC has recently issued a notice of proposed rulemaking to further standardize pipeline transportation tariffs, which if implemented as proposed, may adversely affect the reliability of scheduled interruptible transportation. While any resulting FERC action would affect the Company only indirectly, these inquiries are intended to further enhance competition in natural gas markets. The FERC has also recently acted on rehearing in a proceeding involving its regulatory treatment of pipelines located in offshore federal waters, and has applied the announced policy in several individual proceedings to assert jurisdiction over several proposed projects. The Company's natural gas gathering operations may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement, and management of facilities. Pipeline safety issues have recently become the subject of increasing focus in various political and administrative arenas at both the state and federal levels. For example, an industry supported bill was enacted in 1996. Additional pending legislation would, among other things, increase the frequency with which certain pipelines must be inspected, as well as increase potential civil and criminal penalties for violations of pipeline safety requirements. 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. 10
13 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 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. Thus, the Company cannot predict the ultimate outcome or durability of the unbundled regulatory regime mandated by Order No. 636. 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. It is not anticipated 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 operates under federal and provincial legislation and regulations governing land tenure, royalties, production rates, environmental protection, exports and other matters. The price of natural gas and crude oil in Canada has been deregulated and is now determined by market conditions and negotiations between buyers and sellers. Various matters relating to the transportation and export of natural gas continue to be subject to regulation by both provincial and federal agencies; however, the North American Free Trade Agreement may have reduced the risk of altering cross-border commercial transactions. 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. Effective December 14, 1995, the Company ceased to be included in the consolidated federal income tax return filed by Enron Corp., and the tax allocation agreement (the "Base Agreement") previously in effect between the Company and Enron Corp. was terminated. In addition, effective December 14, 1995, the Company and Enron Corp. entered into a new tax agreement (the "1995 Agreement") pursuant to which, among other things, Enron Corp. agreed (in exchange for the payment of $13 million by the Company) to be liable for, and indemnify the Company against, all U.S. federal and state income taxes and certain foreign taxes imposed on the Company for periods prior to the date Enron Corp. reduced its ownership in the Company to less than 80%. In 1997, the Company and Enron Corp. agreed to terminate the 1995 Agreement and enter into a new tax allocation agreement. In the new agreement, Enron Corp. agreed to refund the $13 million payment made by the Company pursuant to the 1995 Agreement, the Company agreed to release 11
14 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 the Base 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 to be repaid in annual installments through January 1, 2001. The Company does not believe that the cessation of consolidated tax reporting with Enron Corp., the termination of the Base Agreement concurrent with deconsolidation, the signing of the 1995 Agreement and/or the newest tax allocation agreement with Enron Corp. have had or will have in the future a material adverse effect on its financial condition or results of operations. 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 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 12
15 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 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 13
16 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. 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 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 $5.3 million in 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 14
17 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 1996. This imbalance in parity has been 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 a decrease in average wellhead natural gas prices realized by the Company of 20% from 1994 to 1995, the average North America wellhead natural gas price received by the Company increased 43% from 1995 to 1996 and 15% from 1996 to 1997. 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, 1997, the Company had outstanding natural gas costless collar transactions, designated as hedges, covering approximately 37 trillion British thermal units ("TBtu") of natural gas for 1998 and price swaps covering 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. At December 31, 1997, the Company had outstanding options, exercisable by a counterparty, covering notional natural gas volumes averaging 3 TBtu per month during 1998. The fair value of these options at December 31, 1997 was a revenue reduction of $10.5 million. The Company also had outstanding at December 31, 1997 natural gas price swap positions in the same notional quantities as the 1998 options with a fair value revenue increase of $4.2 million. At December 31, 1997, based on the portion of the Company's anticipated natural gas volumes for 1998 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 15
18 prices is approximately $19 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 $5 million for $1.00 per barrel change in average wellhead crude oil prices. 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 $47 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, 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 current exchange and repatriation losses, as well as changes in laws, regulations and policies governing operations of foreign companies generally. 16
19 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.............................. 64 Chairman of the Board and Chief Executive Officer; Director Mark G. Papa.................................... 51 President and Chief Operating Officer and President, North America Operations Edmund P. Segner, III........................... 44 Vice Chairman and Chief of Staff Dennis M. Ulak.................................. 44 President, International Operations and Chairman of the Board and Chief Executive Officer, Enron Oil & Gas International, Inc. Jeffrey B. Sherrick............................. 43 President and Chief Operating Officer, Enron Oil & Gas International, Inc. Barry Hunsaker, Jr.............................. 47 Senior Vice President and General Counsel Loren M. Leiker................................. 44 Senior Vice President, Exploration Walter C. Wilson................................ 55 Senior Vice President and Chief Financial Officer Ben B. Boyd..................................... 56 Vice President and Controller </TABLE> Forrest E. Hoglund joined the Company as Chairman of the Board, Chief Executive Officer and Director in September 1987. He also served as President of the Company 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 Operating Officer in September 1997 and President of the Company in December 1996 and has been President - North America Operations since February 1994. 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. 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. Loren M. Leiker joined the Company in April 1989 and has been Senior Vice President, Exploration since March 1997. Mr. Leiker was previously Vice President, Exploration of the Company. Walter C. Wilson joined the Company in November 1987 and has been Senior Vice President and Chief Financial Officer since May 1991. Ben B. Boyd joined the Company in March 1989 and has been Vice President and Controller since March 1991. 17
20 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 and development activities, or both, 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. 18
21 Acreage. The following table summarizes the Company's developed and undeveloped acreage at December 31, 1997. 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.................... 17,691 14,951 746,318 727,230 764,009 742,181 Texas......................... 275,995 182,999 518,376 364,083 794,371 547,082 Offshore Gulf of Mexico....... 312,726 141,080 541,891 404,956 854,617 546,036 Wyoming....................... 148,999 113,124 262,786 218,658 411,785 331,782 Oklahoma...................... 148,637 85,494 113,274 83,123 261,911 168,617 New Mexico.................... 60,136 31,070 84,224 52,519 144,360 83,589 Utah.......................... 57,820 46,512 33,062 27,564 90,882 74,076 Kansas........................ 9,698 8,699 4,013 2,987 13,711 11,686 Colorado...................... 8,353 1,233 26,380 13,645 34,733 14,878 Mississippi................... 4,761 4,516 33,161 25,524 37,922 30,040 Pennsylvania.................. 1,103 735 16,089 10,727 17,192 11,462 Louisiana..................... 6,131 4,938 4,608 1,592 10,739 6,530 Other......................... 5,793 3,396 6,788 4,766 12,581 8,162 --------- --------- --------- --------- --------- --------- Total................. 1,057,843 638,747 2,390,970 1,937,374 3,448,813 2,576,121 Canada Alberta....................... 359,080 228,908 288,887 245,067 647,967 473,975 Saskatchewan.................. 191,483 175,677 223,228 217,182 414,711 392,859 Manitoba...................... 11,743 9,954 23,848 21,956 35,591 31,910 British Columbia.............. 656 164 6,138 6,138 6,794 6,302 --------- --------- --------- --------- --------- --------- Total Canada.......... 562,962 414,703 542,101 490,343 1,105,063 905,046 Other International China......................... - - 1,849,531 924,766 1,849,531 924,766 Venezuela..................... - - 268,413 241,572 268,413 241,572 India......................... 98,300 29,490 564,307 169,292 662,607 198,782 Trinidad...................... 4,200 3,990 171,459 167,716 175,659 171,706 France........................ - - 168,032 168,032 168,032 168,032 --------- --------- --------- --------- --------- --------- Total Other International....... 102,500 33,480 3,021,742 1,671,378 3,124,242 1,704,858 --------- --------- --------- --------- --------- --------- Total............... 1,723,305 1,086,930 5,954,813 4,099,095 7,678,118 5,186,025 ========= ========= ========= ========= ========= ========= </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 and India at December 31, 1997. Gross gas and oil wells include 279 with multiple completions. <TABLE> <CAPTION> PRODUCTIVE WELLS ---------------- GROSS NET ------ ------ <S> <C> <C> Gas......................................................... 4,622 3,413 Oil......................................................... 703 464 ----- ----- Total............................................. 5,325 3,877 ===== ===== </TABLE> 19
22 Drilling and Acquisition Activities. During the years ended December 31, 1997, 1996 and 1995 the Company spent approximately $693 million, $599 million and $514 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, ------------------------------------------------ 1997 1996 1995 -------------- -------------- -------------- GROSS NET GROSS NET GROSS NET ----- ------ ----- ------ ----- ------ <S> <C> <C> <C> <C> <C> <C> Development Wells Completed North America Gas......................................... 467 352.90 396 325.04 334 251.06 Oil......................................... 94 74.85 80 57.46 69 55.16 Dry......................................... 101 80.01 80 68.77 61 49.21 --- ------ --- ------ --- ------ Total.................................. 662 507.76 556 451.27 464 355.43 Outside North America Gas......................................... 12 3.60 - - 3 2.85 Oil......................................... 6 1.80 1 .30 3 2.85 Dry......................................... - - - - 1 .95 --- ------ --- ------ --- ------ Total.................................. 18 5.40 1 .30 7 6.65 --- ------ --- ------ --- ------ Total Development.............................. 680 513.16 557 451.57 471 362.08 --- ------ --- ------ --- ------ Exploratory Wells Completed North America Gas......................................... 8 5.12 14 10.36 5 4.13 Oil......................................... - - 1 .78 8 3.61 Dry......................................... 12 7.53 26 19.00 21 13.28 --- ------ --- ------ --- ------ Total.................................. 20 12.65 41 30.14 34 21.02 Outside North America Gas......................................... - - - - 6 4.90 Oil......................................... - - - - - - Dry......................................... - - 1 .50 - - --- ------ --- ------ --- ------ Total.................................. - - 1 .50 6 4.90 --- ------ --- ------ --- ------ Total Exploratory.............................. 20 12.65 42 30.64 40 25.92 --- ------ --- ------ --- ------ Total.................................. 700 525.81 599 482.21 511 388.00 Wells in Progress at end of period............... 44 36.39 87 61.08 52 32.71 --- ------ --- ------ --- ------ Total.................................. 744 562.20 686 543.29 563 420.71 === ====== === ====== === ====== Wells Acquired Gas......................................... 227 82.45* 350 148.20* 277 101.70* Oil......................................... 48 20.50* 5 .65 5 .46* --- ------ --- ------ --- ------ Total.................................. 275 102.95 355 148.85 282 102.16 === ====== === ====== === ====== </TABLE> - --------------- * Includes the acquisition of additional interests in certain wells in which the Company previously held 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. 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. 20
23 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. 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 1997. 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> 1995 First Quarter......................................... $24.88 $17.13 $.03 Second Quarter........................................ 24.75 20.25 .03 Third Quarter......................................... 25.38 20.00 .03 Fourth Quarter........................................ 24.88 18.75 .03 1996 First Quarter......................................... $28.50 $22.38 $.03 Second Quarter........................................ 28.63 23.88 .03 Third Quarter......................................... 30.63 22.88 .03 Fourth Quarter........................................ 28.38 23.25 .03 1997 First Quarter......................................... $27.00 $19.88 $.03 Second Quarter........................................ 21.75 17.50 .03 Third Quarter......................................... 25.06 17.69 .03 Fourth Quarter........................................ 23.81 18.50 .03 </TABLE> As of March 1, 1998, there were approximately 376 record holders of the Company's common stock, including individual participants in security position listings. There are an estimated 21,000 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 and development expenditure opportunities and future business prospects of the Company. 21
24 ITEM 6. SELECTED FINANCIAL DATA <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, ------------------------------------------------------------------ 1997 1996 1995 1994 1993 ---------- ---------- ---------- ---------- ---------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) <S> <C> <C> <C> <C> <C> STATEMENT OF INCOME DATA: Net operating revenues....... $ 783,501 $ 730,648 $ 648,702 $ 625,823 $ 581,020 Operating expenses Lease and well............. 96,064 76,618 69,463 60,384 59,344 Exploration................ 57,696 55,009 42,044 41,811 36,921 Dry hole................... 17,303 13,193 12,911 17,197 18,355 Impairment of unproved oil and gas properties...... 27,213 21,226 23,715 24,936 20,467 Depreciation, depletion and amortization............ 278,179 251,278 216,047 242,182 249,704 General and administrative.......... 54,415 56,405 56,626 51,418 45,274 Taxes other than income.... 59,856 48,089 32,587 28,254 35,396 ---------- ---------- ---------- ---------- ---------- Total.............. 590,726 521,818 453,393 466,182 465,461 ---------- ---------- ---------- ---------- ---------- Operating income............. 192,775 208,830 195,309 159,641 115,559 Other income (expense), net ........................... (1,588) (5,007) 669 2,783 6,635 Interest expense (net of interest capitalized)...... 27,717 12,861 11,924 8,489 9,921 ---------- ---------- ---------- ---------- ---------- Income before income taxes ........................... 163,470 190,962 184,054 153,935 112,273 Income tax provision (benefit)(1)............... 41,500(2) 50,954(3) 41,936(4) 5,937(5) (25,752)(6) ---------- ---------- ---------- ---------- ---------- Net income................... $ 121,970 $ 140,008 $ 142,118 $ 147,998 $ 138,025 ========== ========== ========== ========== ========== Earnings per share of common stock(7) Basic...................... $ .78 $ .88 $ .89 $ .93 $ .86 ========== ========== ========== ========== ========== Diluted.................... $ .77 $ .87 $ .88 $ .92 $ .85 ========== ========== ========== ========== ========== Average number of common shares(7) Basic...................... 157,376 159,853 159,917 159,845 159,966 ========== ========== ========== ========== ========== Diluted.................... 158,160 161,525 161,132 160,654 161,784 ========== ========== ========== ========== ========== </TABLE> <TABLE> <CAPTION> AT DECEMBER 31, ------------------------------------------------------------------ 1997 1996 1995 1994 1993 ---------- ---------- ---------- ---------- ---------- (IN THOUSANDS) <S> <C> <C> <C> <C> <C> BALANCE SHEET DATA: Oil and gas properties - net........... $2,387,207 $2,099,589 $1,881,545 $1,684,811 $1,546,045 Total assets................. 2,723,355 2,458,353 2,147,258 1,861,867 1,811,162 Long-term debt Trade...................... 548,775 466,089 147,559 165,337 153,000 Affiliate.................. 192,500 - 141,520 25,000 - Deferred revenue............. 39,918 56,383 205,453 184,183 227,528 Shareholders' equity......... 1,281,049 1,265,090 1,163,659 1,043,419 933,073 </TABLE> - --------------- (1) Includes benefits of approximately $12 million, $16 million, $22 million, $36 million and $65 million in 1997, 1996, 1995, 1994 and 1993, respectively, relating to tight gas sand federal income tax credits. (2) 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. (3) 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. (4) Includes a benefit of approximately $14 million associated with the successful resolution on audit of federal income taxes for certain prior years. (5) 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 22
25 from the reduction of the Company's deferred federal income tax liability resulting from a reevaluation of deferred tax requirements. (6) Includes a benefit of $12 million from the reduction of the Company's deferred federal income tax liability resulting from a reevaluation of deferred tax requirements partially offset by an approximate $7 million predominantly noncash charge primarily to adjust the Company's accumulated deferred federal income tax liability for the increase in the corporate federal income tax rate from 34% to 35%. (7) In May 1994, the Board of Directors declared a two-for-one split of the common stock of the Company to be effected as a nontaxable dividend of one share for each share outstanding. Shares were issued on June 15, 1994 to shareholders of record as of May 31, 1994. All per share amounts presented herein are reflected on a post-split basis. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following review of operations for each of the three years in the period ended December 31, 1997 should be read in conjunction with the consolidated financial statements of the Company and notes thereto beginning with page F-1. RESULTS OF OPERATIONS Net Operating Revenues. Wellhead volume and price statistics for the specified years were as follows: <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, -------------------------- 1997 1996 1995 ------ ------ ------ <S> <C> <C> <C> Natural Gas Volumes (MMcf per day) North America(1).......................................... 758 706 636 Trinidad.................................................. 113 124 107 India..................................................... 18 - - ------ ------ ------ Total............................................. 889 830 743 ====== ====== ====== Average Natural Gas Prices ($/Mcf) North America(2).......................................... $ 2.20 $ 1.92 $ 1.34 Trinidad.................................................. 1.05 1.00 .97 India..................................................... 2.79 - - Composite......................................... 2.07 1.78 1.29 Crude Oil and Condensate Volumes (MBbl per day) North America............................................. 14.2 11.6 11.5 Trinidad.................................................. 3.4 5.2 5.1 India..................................................... 2.3 2.8 2.5 ------ ------ ------ Total............................................. 19.9 19.6 19.1 ====== ====== ====== Average Crude Oil and Condensate Prices ($/Bbl) North America............................................. $19.33 $21.08 $17.09 Trinidad.................................................. 18.68 19.76 16.07 India..................................................... 20.05 20.17 16.81 Composite.............................................. 19.30 20.60 16.78 Natural Gas Liquids Volumes (MBbl per day) North America............................................. 3.9 2.5 1.4 ====== ====== ====== Average Natural Gas Liquids Prices ($/Bbl) North America............................................. $11.54 $11.99 $11.31 Natural Gas Equivalent Volumes (MMcfe per day) North America............................................. 867 790 713 Trinidad.................................................. 133 156 138 India..................................................... 32 17 15 ------ ------ ------ Total............................................. 1,032 963 866 ====== ====== ====== Total Bcfe Deliveries....................................... 377 353 316 </TABLE> - --------------- (1) Includes 48 MMcf per day in 1997, 1996 and 1995 delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended. (2) Includes an average equivalent wellhead value of $1.73 per Mcf in 1997, $1.17 per Mcf in 1996, and $.80 per Mcf in 1995 for the volumes detailed in note (1), net of transportation costs. 23
26 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. 1996 compared to 1995. During 1996, net operating revenues increased $82 million to $731 million as compared to 1995. Average wellhead natural gas prices for 1996 were up approximately 38% from the comparable period in 1995 increasing net operating revenues by approximately $150 million. A 12% increase in wellhead natural gas volumes from 1995 added net operating revenues of approximately $42 million. The increase in North America wellhead natural gas volumes was primarily the result of eliminating voluntary curtailments in the United States during 1996 due to significant increases realized in average wellhead natural gas prices over the prices realized in 1995. Wellhead crude oil and condensate average prices increased 23% adding approximately $27 million to net operating revenues over 1995. Wellhead crude oil and condensate volumes increased 3% from the comparable period a year ago adding approximately $4 million to net operating revenues. Gains on the sales of reserves and related assets totaled $20 million in 1996 as compared to $63 million realized in 1995, 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 increased net operating revenues by only $4 million during 1996, a decrease of approximately $101 million from 1995. This decrease primarily resulted from a lower revenue increase on natural gas commodity price hedging activities utilizing NYMEX-related commodity market transactions in 1996 of $13 million compared to a $65 million revenue increase on similar transactions in 1995. The Company also incurred a $13 million revenue reduction related to certain trading transactions in 1996 compared to a $3 million revenue increase in 1995. A decrease in margins associated with sales and purchases of natural gas and the volumetric production payment reduced net revenues by approximately $17 million as compared to 1995 as a result of the higher costs of natural gas delivered. Additionally, the Company incurred a $13 million revenue reduction on its NYMEX-related crude oil price swap transactions in 1996 compared to $2 million revenue increase in 1995. 24
27 Operating Expenses 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. Depreciation, depletion and amortization ("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 thousand cubic feet equivalent ("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. 1996 compared to 1995. During 1996, operating expenses of $522 million were approximately $69 million higher than the $453 million incurred in 1995. Lease and well expenses increased approximately $7 million to $77 million primarily due to continually expanding operations and increases in production activity. Exploration expense increased approximately $13 million to $55 million primarily due to increased exploratory drilling activities in North America. DD&A expense increased $35 million to $251 million primarily reflecting increased production volumes and an increase in the average DD&A rate from $.68 per Mcfe in 1995 to $.71 per Mcfe in 1996 due to a change in volume mix by field and geographic location and the impact of the adoption of SFAS No. 121 - "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." Taxes other than income were approximately $16 million higher in 1996 as compared to 1995 primarily due to higher state severance taxes associated with higher taxable wellhead revenues resulting from higher United States volumes and average prices and lower applicable exploration cost deductions in Trinidad in 1996. The Company's total per unit operating costs increased in 1996 for lease and well, DD&A, general and administrative, interest expense, and taxes other than income by $.04 per Mcfe, averaging $1.26 per Mcfe during 1996 compared to $1.22 per Mcfe during 1995. This increase is primarily attributable to increases in per unit DD&A expense and taxes other than income partially offset by a decrease in per unit general and administrative expense. Other Income (Expense). The net expense for 1997 was primarily comprised of expense related to a provision for litigation partially offset by interest income. Interest Expense. The increase in net interest expense of $15 million from 1996 to 1997 and of $1 million from 1995 to 1996 primarily reflects a higher level of debt outstanding in each subsequent period. (See Note 4 to Consolidated Financial Statements). Income Taxes. Income tax provision decreased over $9 million for 1997 as compared to 1996 primarily due to lower income before income taxes. Approximately $15 million in benefits related to the sales of certain international assets and subsidiaries, the refiling of certain Canadian tax returns and other miscellaneous benefits were essentially equal to the Canadian benefit and other items reported in 1996, as discussed below. Income tax provision increased $9 million for 1996 as compared to 1995 primarily as a result of lower benefits associated with tight gas sands federal income tax credits utilized in 1996 as compared to 1995. Tax benefits associated with a reassessment of deferred tax requirements and the successful resolution on audit of 25
28 Canadian income taxes for certain prior years of $9 million and other miscellaneous benefits in 1996 were essentially equal to an unrelated $14 million benefit in 1995. CAPITAL RESOURCES AND LIQUIDITY Cash Flow. The primary sources of cash for the Company during the three-year period ended December 31, 1997 included funds generated from operations, proceeds from the sales of selected oil and gas reserves and related assets, proceeds from new borrowings and proceeds from the sales of treasury stock in conjunction with the exercise of stock options. 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. 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 expenses and to include proceeds from sales of reserves and related assets. The Company generated discretionary cash flow of approximately $545 million in 1997, $543 million in 1996, and $525 million in 1995. Net operating cash flows of $531 million for 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 operating cash flows of $365 million for 1996 increased approximately $30 million as compared to 1995 primarily due to higher production related net operating revenues net of cash operating expenses partially offset by higher current federal income taxes and increased working capital requirements primarily associated with higher accounts receivable due to higher wellhead prices and an increase in international activities, net of higher accounts payable, at year end 1996. In accordance with the requirements of SFAS No. 95 - "Statement of Cash Flows", net proceeds from the sale of selected oil and gas reserves and related assets are not included in the determination of net operating cash flows. Sale of Volumetric Production Payment. In September 1992, the Company sold a volumetric production payment for $326.8 million to a limited partnership. (See "Business - Marketing - Other Marketing" and Note 5 to Consolidated Financial Statements). Under the terms of the production payment agreements, the Company conveyed a real property interest in approximately 124 Bcfe (136 TBtu) of certain natural gas and other hydrocarbons to the purchaser. Effective October 1, 1993, the agreements were amended providing for the extension of the original term of the volumetric production payment through March 31, 1999 and including a revised schedule of daily quantities of hydrocarbons to be delivered which is approximately one-half of the original schedule. The revised schedule will total approximately 89.1 Bcfe (97.8 TBtu) versus approximately 87.9 Bcfe (96.4 TBtu) remaining to be delivered under the original agreement. The Company retains responsibility for its working interest share of the cost of operations. In accordance with generally accepted accounting principles, the Company accounted for the proceeds received in the transaction as deferred revenue which is being amortized into revenue and income as natural gas and other hydrocarbons are produced and delivered to the purchaser during the term, as revised, of the volumetric production payment thereby matching those revenues with the depreciation of asset values which remained on the balance sheet following the sale and the operating expenses incurred for which the Company retained responsibility. The Company expects the above transaction, as amended, to have minimal impact on future earnings. However, cash made available by the sale of the volumetric production payment has provided considerable financial flexibility for the pursuit of investment alternatives. 26
29 Exploration and Development Expenditures. The table below sets out components of actual exploration and development expenditures for the years ended December 31, 1997, 1996 and 1995, along with those budgeted for the year 1998. <TABLE> <CAPTION> ACTUAL -------------------- BUDGETED EXPENDITURE CATEGORY 1997 1996 1995 1998 -------------------- ---- ---- ---- -------- (IN MILLIONS) <S> <C> <C> <C> <C> Capital Drilling and Facilities.......................... $446 $408 $303 Leasehold Acquisitions........................... 77 45 22 Producing Property Acquisitions.................. 81 69 127 Capitalized Interest and Other................... 22 18 12 ---- ---- ---- Total.................................... 626 540 464 Exploration Expenses............................... 75 68 55 ---- ---- ---- ---- Total.............................................. $701 $608 $519 $700 ==== ==== ==== ==== </TABLE> Exploration and development expenditures increased $93 million 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. Exploration and development expenditures increased $89 million in 1996 as compared to 1995 primarily due to increased development expenditures in the United States and India and increased exploration expenditures in the United States. Partially offsetting these increases were the reduction in 1996 of development expenditures in Trinidad due to the completion of a large development drilling program in 1995 and reduced property acquisition expenditures. (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 1998 exploration and development expenditure plans). Hedging Transactions. With the objective of enhancing the certainty of future revenues, the Company enters into NYMEX-related commodity price swaps from time to time. 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. The Company's 1997 NYMEX-related natural gas and crude oil commodity price swaps closed with "other marketing revenue" reductions of $51 million pretax and $5 million pretax, respectively. The Company has entered into natural gas costless collar commodity price swap transactions which have a floor price and a ceiling price. At December 31, 1997, there were outstanding natural gas costless collars for 1998 covering approximately 37 TBtu of natural gas at a weighted average floor price of $2.12 per MMBtu and ceiling price of $2.72 per MMBtu. At December 31, 1997, there were open crude oil commodity price swaps for 1998 covering approximately 1.3 million barrels of crude oil at a weighted average price of $18.90 per barrel. Financing. The Company's long-term debt-to-total-capital ratio was 37% and 27% as of December 31, 1997 and 1996, respectively. The Company has entered into agreements with Enron Corp. pursuant to which the Company may borrow funds from or invest funds with Enron Corp. at representative market rates of interest on a revolving basis. Advances from Enron Corp. of $193 million were outstanding as of December 31, 1997. There were no advances outstanding as of December 31, 1996. There were no investments with Enron Corp. as of December 31, 1997 or 1996. These agreements are used primarily to facilitate efficient cash management. During 1997, total long-term debt increased $275 million to $741 million as a result of borrowings related to increased exploration and development expenditures and 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, 1997 and 1996 was $744 million and $464 million, respectively, based upon quoted market 27
30 prices and, where such prices were not available, upon interest rates currently available to the Company at year end. (See Note 13 to the Consolidated Financial Statements). Outlook. Uncertainty continues to exist as to the direction of future North America natural gas 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, the deregulation of the natural gas market under Federal Energy Regulatory Commission Order 636 and subsequent related orders, improvements being realized in the availability and utilization of natural gas storage capacity, colder weather experienced in the latter part of 1995 and 1996 than in prior years and warmer than normal weather experienced in late 1997 and early 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, 1997, based on the portion of the Company's anticipated natural gas volumes for 1998 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 $5 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, the winning in 1996 of a concession in Venezuela, the award of the modified U(a) block offshore Trinidad and the 1997 signing of a production sharing contract 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 in its expenditure plans 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). Early-in-year activity will be managed within an annual expected expenditure level of approximately $700 million for 1998. This early-in-year planning will address the continuing uncertainty with regard to the future of the North America natural gas price environment and will be structured to maintain the flexibility necessary under the Company's continuing strategy of funding exploration, exploitation, development and acquisition activities primarily from available internally generated cash flow. The level of exploration and development expenditures may vary in 1998 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 1998 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 that are more certain 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 December 31, 1992, the Company continued in 1997, and should continue in the future, to realize significant but declining 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 28
31 benefit, which was approximately $12 million in 1997 and is estimated to be approximately $10 million for 1998, 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 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 Credit (Section 29) and Severance Tax Exemption"). Other natural gas marketing activities are also expected to continue to contribute meaningfully to financial results. Other. The cost of environmental compliance has not been material to the Company. 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 and producing reserves and in acquiring oil and gas properties, political developments around the world and conditions of the capital and equity markets during the periods covered by the forward looking statements. 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. 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. 29
32 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 October 27, 1997 reporting the sale of $100 million principal amount of 6.5% Notes due September 15, 2004 pursuant to an underwritten public offering. The Company filed a Report on Form 8-K on December 10, 1997 reporting the sale of $100 million principal amount of 6.5% Notes due December 1, 2007 pursuant to an underwritten public offering. 30
33 INDEX TO FINANCIAL STATEMENTS ENRON OIL & GAS COMPANY <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 for Each of the Three Years in the Period Ended December 31, 1997............ F-4 Consolidated Balance Sheets - December 31, 1997 and 1996................................................... F-5 Consolidated Statements of Shareholders' Equity for Each of the Three Years in the Period Ended December 31, 1997................................................... F-6 Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 1997...... 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 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. </TABLE> F-1
34 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. Their audits of the years presented included developing an overall understanding of the Company's accounting systems, procedures and internal controls, and conducting tests and other auditing procedures sufficient to support their opinion on the financial statements. 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 for the year ended December 31, 1997. <TABLE> <S> <C> <C> WALTER C. WILSON FORREST E. HOGLUND Senior Vice Chairman of the BEN B. BOYD President Board and Vice President and Chief Financial Chief Executive Controller Office Officer </TABLE> Houston, Texas February 23, 1998 F-2
35 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, 1997 and 1996, and the related consolidated statements of income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 1997. 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, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, 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. Houston, Texas ARTHUR ANDERSEN LLP February 23, 1998 F-3
36 ENRON OIL & GAS COMPANY CONSOLIDATED STATEMENTS OF INCOME (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, -------------------------------- 1997 1996 1995 -------- -------- -------- <S> <C> <C> <C> NET OPERATING REVENUES Natural Gas Trade................................................. $544,181 $393,129 $222,118 Associated Companies.................................. 71,339 164,745 229,997 Crude Oil, Condensate and Natural Gas Liquids Trade................................................. 121,838 108,365 66,145 Associated Companies.................................. 29,951 37,539 58,233 Gains on Sales of Reserves and Related Assets............ 9,287 20,358 62,821 Other.................................................... 6,905 6,512 9,388 -------- -------- -------- Total............................................ 783,501 730,648 648,702 OPERATING EXPENSES Lease and Well........................................... 96,064 76,618 69,463 Exploration.............................................. 57,696 55,009 42,044 Dry Hole................................................. 17,303 13,193 12,911 Impairment of Unproved Oil and Gas Properties............ 27,213 21,226 23,715 Depreciation, Depletion and Amortization................. 278,179 251,278 216,047 General and Administrative............................... 54,415 56,405 56,626 Taxes Other Than Income.................................. 59,856 48,089 32,587 -------- -------- -------- Total............................................ 590,726 521,818 453,393 -------- -------- -------- OPERATING INCOME........................................... 192,775 208,830 195,309 OTHER INCOME (EXPENSE), NET................................ (1,588) (5,007) 669 -------- -------- -------- INCOME BEFORE INTEREST EXPENSE AND TAXES................... 191,187 203,823 195,978 INTEREST EXPENSE Incurred Trade................................................. 41,399 20,383 17,054 Affiliate............................................. 24 1,614 1,360 Capitalized.............................................. (13,706) (9,136) (6,490) -------- -------- -------- Net Interest Expense............................. 27,717 12,861 11,924 -------- -------- -------- INCOME BEFORE INCOME TAXES................................. 163,470 190,962 184,054 INCOME TAX PROVISION....................................... 41,500 50,954 41,936 -------- -------- -------- NET INCOME................................................. $121,970 $140,008 $142,118 ======== ======== ======== EARNINGS PER SHARE OF COMMON STOCK Basic.................................................... $ .78 $ .88 $ .89 ======== ======== ======== Diluted.................................................. $ .77 $ .87 $ .88 ======== ======== ======== AVERAGE NUMBER OF COMMON SHARES Basic.................................................... 157,376 159,853 159,917 ======== ======== ======== Diluted.................................................. 158,160 161,525 161,132 ======== ======== ======== </TABLE> The accompanying notes are an integral part of these consolidated financial statements. F-4
37 ENRON OIL & GAS COMPANY CONSOLIDATED BALANCE SHEETS (IN THOUSANDS) <TABLE> <CAPTION> AT DECEMBER 31, ------------------------- 1997 1996 ----------- ----------- <S> <C> <C> ASSETS CURRENT ASSETS Cash and Cash Equivalents................................. $ 9,330 $ 7,644 Accounts Receivable Trade.................................................. 185,979 195,239 Associated Companies................................... 46,120 82,059 Inventories............................................... 32,040 20,746 Other..................................................... 8,566 20,222 ----------- ----------- Total............................................. 282,035 325,910 OIL AND GAS PROPERTIES (Successful Efforts Method).......... 4,291,405 3,753,199 Less: Accumulated Depreciation, Depletion and Amortization........................................... (1,904,198) (1,653,610) ----------- ----------- Net Oil and Gas Properties........................ 2,387,207 2,099,589 OTHER ASSETS................................................ 54,113 32,854 ----------- ----------- TOTAL ASSETS................................................ $ 2,723,355 $ 2,458,353 =========== =========== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Accounts Payable Trade.................................................. $ 198,109 $ 200,069 Associated Companies................................... 37,613 77,522 Accrued Taxes Payable..................................... 28,841 18,554 Dividends Payable......................................... 4,705 4,818 Other..................................................... 21,729 16,397 ----------- ----------- Total............................................. 290,997 317,360 LONG-TERM DEBT Trade..................................................... 548,775 466,089 Affiliate................................................. 192,500 - OTHER LIABILITIES Trade..................................................... 37,739 44,483 Associated Companies...................................... 44,699 - DEFERRED INCOME TAXES....................................... 287,678 308,948 DEFERRED REVENUE............................................ 39,918 56,383 COMMITMENTS AND CONTINGENCIES 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................................ 402,877 388,212 Unearned Compensation..................................... (4,694) (5,727) Cumulative Foreign Currency Translation Adjustment........ (19,771) (10,179) Retained Earnings......................................... 800,709 697,564 Common Stock Held in Treasury, 4,935,744 shares at December 31, 1997 and 242,882 shares at December 31, 1996................................................... (99,672) (6,380) ----------- ----------- Total Shareholders' Equity........................ 1,281,049 1,265,090 ----------- ----------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY.................. $ 2,723,355 $ 2,458,353 =========== =========== </TABLE> The accompanying notes are an integral part of these consolidated financial statements. F-5
38 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, 1994....................... $201,600 $403,488 $ - $ (15,298) $453,810 $ (181) $1,043,419 Net Income................. - - - - 142,118 - 142,118 Dividends Paid/Declared, $.12 Per Share........... - - - - (19,188) - (19,188) Translation Adjustment..... - - - 4,551 - - 4,551 Treasury Stock Purchased... - - - - - (17,855) (17,855) Treasury Stock Issued Under Stock Option Plans....... - (4,109) - - - 14,438 10,329 Other...................... - - - - - 285 285 -------- -------- ------- --------- -------- -------- ---------- 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 Option 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 Option 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 ======== ======== ======= ========= ======== ======== ========== </TABLE> The accompanying notes are an integral part of these consolidated financial statements. F-6
39 ENRON OIL & GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS) <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, ----------------------------------- 1997 1996 1995 --------- --------- --------- <S> <C> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES Reconciliation of Net Income to Net Operating Cash Inflows: Net Income............................................ $ 121,970 $ 140,008 $ 142,118 Items Not Requiring (Providing) Cash Depreciation, Depletion and Amortization........... 278,179 251,278 216,047 Impairment of Unproved Oil and Gas Properties...... 27,213 21,226 23,715 Deferred Income Taxes.............................. 16,665 2,276 45,173 Other, Net......................................... 359 7,830 2,910 Exploration Expenses.................................. 57,696 55,009 42,044 Dry Hole Expenses..................................... 17,303 13,193 12,911 Gains on Sales of Reserves and Related Assets......... (9,287) (20,358) (62,821) Other, Net............................................ (2,590) 8,871 720 Changes in Components of Working Capital and Other Liabilities Accounts Receivable.............................. 48,893 (120,370) (17,525) Inventories...................................... (11,294) (9,049) 4,034 Accounts Payable................................. (11,478) 87,495 2,514 Accrued Taxes Payable............................ 10,287 (1,041) 1,964 Other Liabilities................................ 2,521 3,752 1,544 Other, Net....................................... 9,760 270 (18,791) Amortization of Deferred Revenue...................... (43,345) (43,463) (43,344) Changes in Components of Working Capital Associated with Investing and Financing Activities............ 18,077 (31,817) (17,858) --------- --------- --------- NET OPERATING CASH INFLOWS.............................. 530,929 365,110 335,355 INVESTING CASH FLOWS Additions to Oil and Gas Properties................... (626,198) (539,330) (445,047) Exploration Expenses.................................. (57,696) (55,009) (42,044) Dry Hole Expenses..................................... (17,303) (13,193) (12,911) Proceeds from Sales of Reserves and Related Assets (Note 10).......................................... 37,521 63,951 102,006 Changes in Components of Working Capital Associated with Investing Activities.......................... (22,454) 37,402 18,391 Other, Net............................................ (11,000) (5,381) (11,689) --------- --------- --------- NET INVESTING CASH OUTFLOWS............................. (697,130) (511,560) (391,294) FINANCING CASH FLOWS Long-Term Debt Trade.............................................. 86,595 320,580 (16,100) Affiliate.......................................... 192,500 (141,520) 116,520 Dividends Paid........................................ (18,938) (19,161) (19,193) Treasury Stock Purchased.............................. (99,306) (43,507) (17,855) Proceeds from Sales of Treasury Stock................. 5,141 22,188 10,329 Other, Net............................................ 1,895 (7,525) (533) --------- --------- --------- NET FINANCING CASH INFLOWS.............................. 167,887 131,055 73,168 --------- --------- --------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........ 1,686 (15,395) 17,229 CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR.......... 7,644 23,039 5,810 --------- --------- --------- CASH AND CASH EQUIVALENTS AT END OF YEAR................ $ 9,330 $ 7,644 $ 23,039 ========= ========= ========= </TABLE> The accompanying notes are an integral part of these consolidated financial statements. F-7
40 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"), 55% of the outstanding common stock of which was owned by Enron Corp. as of December 31, 1997, 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 Equivalents. The Company records as cash equivalents all highly liquid short-term investments with maturities of three months or less. 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", which resulted in a non-cash impairment charge that was immaterial to and is included in depreciation, depletion and amortization. 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. F-8
41 Gains and losses associated with the sale in place of natural gas and crude oil reserves and related assets are classified as net operating revenues in the consolidated statements of income based on the Company's strategy of continuing such sales in maximizing 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, 1997 are set out in the consolidated statements of income. Income Taxes. The closing on December 13, 1995 of the sale by Enron Corp. of approximately 31 million outstanding shares of the common stock of the Company reduced Enron Corp.'s ownership interest in the Company below 80% with the result that (i) the Company ceased, effective December 14, 1995, to be included in the consolidated federal income tax return filed by Enron Corp. and (ii) a tax allocation agreement (the "Base Agreement") previously in effect between the Company and Enron Corp. was terminated. In addition, effective December 14, 1995, the Company and Enron Corp. entered into a new tax allocation agreement (the "1995 Agreement") pursuant to which, among other things, Enron Corp. agreed (in exchange for the payment of $13 million by the Company) to be liable for, and indemnify the Company against, all U.S. federal and state income taxes and certain foreign taxes imposed on the Company for periods prior to the date Enron Corp. reduced its ownership in the Company to less than 80%. In 1997, the Company and Enron Corp. agreed to terminate the 1995 Agreement and enter into a new tax allocation agreement. In the new agreement, Enron Corp. agreed to refund the $13 million payment made by the Company pursuant to the 1995 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 the Base Agreement. Enron Corp. also advanced the Company $50 million to fund certain federal income taxes related to the 1995 taxable year. This advance is to be repaid in annual installments through January 1, 2001. The Company does not believe that the cessation of consolidated tax reporting with Enron Corp., the termination of the Base Agreement concurrent with deconsolidation, the signing of the 1995 Agreement and/or the newest tax allocation agreement with Enron Corp. have had or will have in the future a material adverse effect on its financial condition or results of operations. Prior to December 14, 1995, the Company was included in the consolidated federal income tax return filed by Enron Corp. as the common parent for itself and its subsidiaries and the resulting taxes, including taxes for any state or other taxing jurisdiction that required or permitted a consolidated, combined, or unitary tax return to be filed and in which the Company and/or any of its subsidiaries was included, were apportioned as between the Company and/or any of its subsidiaries and Enron Corp. based on the terms of the Base Agreement. 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. F-9
42 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. Earnings Per Share. In accordance with the provisions of SFAS No. 128 - "Earnings per Share", basic earnings per share is computed on the basis of the weighted-average number of common shares outstanding during the periods. Diluted earnings 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. The difference between the Average Number of Common Shares outstanding for basic and diluted earnings per share is due to the assumed issuance of common shares relating to employee stock options in each period presented. 2. NATURAL GAS AND CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS NET OPERATING REVENUES Natural Gas Net Operating Revenues are comprised of the following: <TABLE> <CAPTION> 1997 1996 1995 -------- -------- -------- <S> <C> <C> <C> Wellhead Natural Gas Revenues Trade........................................... $484,565 $323,642 $174,732 Associated Companies(1)(2)...................... 187,199 216,676 173,864 -------- -------- -------- Total................................... $671,764 $540,318 $348,596 ======== ======== ======== Other Natural Gas Marketing Activities Gross Revenues from: Trade(3)..................................... $133,701 $142,149 $102,904 Associated Companies......................... 93,808 92,471 78,985 -------- -------- -------- Total................................... 227,509 234,620 181,889 Associated Costs from: Trade........................................ 73,571 72,633 56,221 Associated Companies(1)(4)................... 162,543 143,871 90,121 -------- -------- -------- Total................................... 236,114 216,504 146,342 -------- -------- -------- Net..................................... (8,605) 18,116 35,547 Commodity Price Transaction Gain (Loss) Trading...................................... 3,370(5) (13,222)(6) 2,688(7) Non-Trading(8)............................... (51,009) 12,662 65,284 -------- -------- -------- Total................................... (47,639) (560) 67,972 -------- -------- -------- Total................................... $(56,244) $ 17,556 $103,519 ======== ======== ======== </TABLE> F-10
43 Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues are comprised of the following: <TABLE> <CAPTION> 1997 1996 1995 -------- -------- -------- <S> <C> <C> <C> Wellhead Crude Oil, Condensate and Natural Gas Liquids Revenues Trade........................................... $121,838 $108,365 $ 66,145 Associated Companies............................ 34,821 50,668 56,681 -------- -------- -------- Total................................... $156,659 $159,033 $122,826 ======== ======== ======== Other Crude Oil and Condensate Marketing Activities Commodity Price Hedging Gain (Loss)(8)....................................... $ (4,870) $(13,129) $ 1,552 ======== ======== ======== </TABLE> - --------------- (1) Wellhead Natural Gas Revenues in 1997, 1996 and 1995 include $114,859, $119,009 and $80,369 respectively, associated with deliveries by Enron Oil & Gas Company to Enron Oil & Gas Marketing, Inc., a wholly-owned subsidiary, reflected as a cost in Other Natural Gas Marketing Activities - Associated Costs. (2) Includes $30,573, $20,656 and $14,022 in 1997, 1996 and 1995, respectively, associated with the equivalent wellhead value of volumes delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended, net of transportation. (3) Includes $43,344, $43,463 and $43,344 in 1997, 1996 and 1995, respectively, associated with the amortization of deferred revenues under the terms of a volumetric production payment agreement effective October 1, 1992, as amended. (4) Includes $44,137, $37,483 and $27,549 in 1997, 1996 and 1995, respectively, for volumes delivered under a volumetric production payment agreement effective October 1, 1992, as amended, including equivalent wellhead value, any applicable transportation costs and exchange differentials. (5) Includes a non-cash revenue increase related to the change in market value of natural gas price swap options exercisable by a counterparty during 1997 and 1998, and of the partially offsetting "buy" price swap positions. This revenue increase is partially offset by a revenue reduction related to the settlement of 1997 transactions. (6) Includes a non-cash charge of $12,000 related to the value of natural gas price swap options exercisable by a counterparty during 1997, 1998, 1999 and 2000. The options for 1997 and 1998 remained open at December 31, 1996; however, "buy" price swap positions in the same notional quantities and maturities are in place. The option agreements for 1999 and 2000 were terminated during the fourth quarter of 1996. See Note 13 for a discussion of the options. (7) Includes an $11,255 revenue increase associated with certain NYMEX-related commodity market transactions designated for trading purposes partially offset by a $2,567 revenue reduction related to call option transactions and a $6,000 revenue reduction associated with certain NYMEX-related natural gas commodity market transactions that were marked-to-market due to loss of correlation between the NYMEX and the wellhead natural gas prices that the positions were designated to hedge. (See Note 13 "Price and Interest Rate Risk Management"). (8) Represents revenue increase (reduction) associated with commodity price swap transactions primarily with Enron Corp. affiliated companies based on NYMEX-related commodity prices in effect on dates of execution, less customary transaction fees. These transactions serve as price hedges for a portion of wellhead sales. 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. Such operating revenues and associated costs through February 28, 1995 were classified as Other Natural Gas Marketing Activities - Gross Revenues and F-11
44 Associated Costs from Associated Companies. The Company will realize net operating revenues classified as Other Natural Gas Marketing Activities - Commodity Price Transaction Gain (Loss), Non-Trading, 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 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 total cash payments receivable under the terms of the Swap Agreements were approximately $13 million and $33 million at December 31, 1997 and 1996, respectively, and are presented in the accompanying balance sheet as Accounts Receivable - Associated Companies for the $9 million and $20 million current portion, respectively, and as Other Assets for the $4 million and $13 million noncurrent portion, respectively. The corresponding total future revenue of approximately $13 million and $33 million, respectively, is classified as Deferred Revenue. (See Note 13 "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, the agreement provides for Enron Corp. to grant 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, 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. Receipt of the options represents a capital contribution from Enron Corp. and, accordingly, the fair value received net of tax effects of $8.2 million has been credited to Additional Paid In Capital. 4. LONG-TERM DEBT Long-Term Debt at December 31 consisted of the following: <TABLE> <CAPTION> 1997 1996 -------- -------- <S> <C> <C> Commercial Paper/Uncommitted Credit Facilities.............. $ 42,415 $ 65,700 9.10% Notes due 1998........................................ 20,000 40,000 6.50% Notes due 2004........................................ 100,000 - 6.70% Notes due 2006........................................ 150,000 150,000 6.50% Notes due 2007........................................ 100,000 - Bank Debt due 1999.......................................... - 30,000 Subsidiary Debt due 1998-2001............................... 136,000 176,000 Other....................................................... 360 4,389 -------- -------- 548,775 466,089 Affiliate................................................... 192,500 - -------- -------- Total............................................. $741,275 $466,089 ======== ======== </TABLE> The Company has a revolving credit agreement with a group of banks that provides for aggregate borrowings of up to $300 million and matures on June 27, 2002. Advances under the agreement bear interest, F-12
45 at the option of the Company, based on a base rate, an adjusted CD rate or a Eurodollar rate. The Company also has a credit agreement with the same group of banks that provides for aggregate borrowings of up to $100 million and matures June 25, 1998. At December 31, 1997, there were no advances outstanding under these agreements. Commercial Paper outstanding at December 31, 1997 of $42.4 million was issued under a commercial paper program the proceeds of which are used to fund current transactions. At December 31, 1996, the Company had an uncommitted credit facilities balance outstanding of $65.7 million. Advances under these credit facilities bear interest based on market rates. Commercial paper and uncommitted credit facilities balances are classified as long-term debt based on the Company's intent and ability to replace such amounts with other long-term debt. The remaining repayment of the 9.10% Notes was made on February 13, 1998. This amount was replaced with other long-term debt. The 6.50% Notes due September 15, 2004 were issued through a public offering in September 1997. These notes have an effective interest rate of 6.65%. The 6.70% Notes due November 15, 2006 were issued through a public offering in November 1996. These notes have an effective interest rate of 6.83%. The 6.50% Notes due December 1, 2007 were issued through a public offering in December 1997. These notes have an effective interest rate of 6.61%. The Subsidiary Debt due 1998-2001 bears interest at variable rates based on the London Interbank Bid or Offered Rates. Subsidiary debt of $31 million is due in 1998 and is classified as long-term based on the Company's intent and ability to replace such amount upon maturity with other long-term debt. Certain of the borrowings described above contain covenants requiring the maintenance of certain financial ratios and limitations on liens, debt issuance and dispositions of assets. All subsidiary debt is guaranteed by the Company. Shelf Registration. The Company may sell from time to time up to an aggregate of $413 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 agreements with Enron Corp. that provide for the borrowing by the Company of up to $200 million through December 31, 1998 and investing by the Company of surplus funds of up to $200 million through December 31, 1998 at market rates from time to time. Advances from Enron Corp. of $192.5 million were outstanding at December 31, 1997, and such balance was classified as long-term based on the Company's intent and ability to replace such amount with other long-term debt. There were no advances outstanding at December 31, 1996. There were no investments with Enron Corp. at December 31, 1997 or 1996. Fair Value Of Long-Term Debt. At December 31, 1997 and 1996, the Company had $741 million and $466 million, respectively, of long-term debt which had fair values of approximately $744 million and $464 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. At December 31, 1997 and 1996 there were approximately 23 trillion British thermal units ("TBtu") and 41 TBtu, respectively, F-13
46 remaining to be delivered under the agreement. Such quantities are scheduled to be delivered 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 is being amortized into revenue and income as natural gas and other hydrocarbons are produced and delivered during the term of the volumetric production payment agreement. Annual remaining amortization of deferred revenue under the volumetric production payment agreement, as amended, at December 31, 1997 was as follows: <TABLE> <S> <C> 1998............................................... $43,344 1999............................................... 10,688 ------- Total.................................... $54,032 ======= </TABLE> 6. SHAREHOLDERS' EQUITY On May 7, 1996, the shareholders of the Company approved a resolution submitted by the Board of Directors to amend the Restated Certificate of Incorporation of the Company to increase the total number of authorized shares of the common stock of the Company from 160 million to 320 million shares. The Board of Directors of the Company approved in December 1992, and amended in September 1994 and December 1996, the authorization for purchasing and holding in treasury at any time of 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. In December 1996, the Board of Directors of the Company 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 of the Company 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, 1997 and 1996, 4,935,744 shares and 242,882 shares, respectively, were held in treasury under these authorizations. (See Note 9 "Commitments and Contingencies - Stock Option Plans"). 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, 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 F-14
47 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, 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. 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 F-15
48 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. Wellhead Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Revenues and Other Natural Gas and Other Crude Oil and Condensate Marketing Activities 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. Other Natural Gas and Other Crude Oil and Condensate Marketing Activities 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 obtained from third parties. (See Note 2 "Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues"). 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 $16.1 million, $17.0 million and $16.4 million for the years ended December 31, 1997, 1996 and 1995, 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 $5.3 million for 1997. Maximum allocated indirect costs under the previous service agreement were $7.5 million and $7.0 million for 1996 and 1995, respectively. 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 $5.3 million was incurred by the Company for indirect general and administrative expenses for 1997. Under the previous agreement, approximately $7.5 million and $6.8 million were charged to the Company for indirect general and administrative expenses for 1996 and 1995, respectively. Financing. See Note 4 "Long-Term Debt - Financing Arrangements with Enron Corp." for a discussion of financing arrangements with Enron Corp. F-16
49 8. INCOME TAXES The principal components of the Company's net deferred income tax liability at December 31, 1997 and 1996 were as follows: <TABLE> <CAPTION> 1997 1996 -------- -------- <S> <C> <C> <C> Deferred Income Tax Assets Cogen Contract Exchange.......................... $ 19,781 $ - Net Operating Loss Carryforward, India........... 27,500 - Non-Producing Leasehold Costs.................... 13,391 9,832 Seismic Costs Capitalized for Tax................ 7,144 7,037 Alternative Minimum Tax Credit Carryforward...... 12,681 7,516 Other............................................ 11,441 5,013 -------- -------- Total Deferred Income Tax Assets......... 91,938 29,398 Deferred Income Tax Liabilities Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization.................... 304,122 278,094 Capitalized Interest............................. 10,231 7,401 Volumetric Production Payment Book Revenue Over Income for Tax................................ 58,850 51,499 Trading Activity................................. 3,470 1,448 Other............................................ 2,943 (96) -------- -------- Total Deferred Income Tax Liabilities.... 379,616 338,346 -------- -------- Net Deferred Income Tax Liability........ $287,678 $308,948 ======== ======== </TABLE> The components of income before income taxes were as follows: <TABLE> <CAPTION> 1997 1996 1995 -------- -------- -------- <S> <C> <C> <C> United States...................................... $103,831 $146,335 $157,174 Foreign............................................ 59,639 44,627 26,880 -------- -------- -------- Total.................................... $163,470 $190,962 $184,054 ======== ======== ======== </TABLE> Total income tax provision (benefit) was as follows: <TABLE> <CAPTION> 1997 1996 1995 -------- -------- -------- <S> <C> <C> <C> Current: Federal.......................................... $ 50,494 $ 21,064 $ (6,983) State............................................ 840 (916) 130 Foreign.......................................... 23,614 28,530 3,616 -------- -------- -------- Total.................................... 74,948 48,678 (3,237) Deferred: Federal.......................................... (32,711) 13,620 24,733 State............................................ 348 (1,826) 855 Foreign.......................................... (1,085) (9,518) 19,585 -------- -------- -------- Total.................................... (33,448) 2,276 45,173 -------- -------- -------- Income Tax Provision............................... $ 41,500 $ 50,954 $ 41,936 ======== ======== ======== </TABLE> F-17
50 The differences between taxes computed at the U.S. federal statutory tax rate and the Company's effective rate were as follows: <TABLE> <CAPTION> 1997 1996 1995 ------ ------ ------- <S> <C> <C> <C> Statutory Federal Income Tax Rate......................... 35.00% 35.00% 35.00% State Income Tax, Net of Federal Benefit.................. 0.47 (0.76) 0.35 Income Tax Related to Foreign Operations.................. 2.83 6.16 7.21 Tight Gas Sand Federal Income Tax Credits................. (7.51) (8.22) (12.19) Revision of Prior Years' Tax Estimates.................... (4.34) (4.46) (6.52) Amended Return Recoveries................................. - - (1.09) Other..................................................... (1.06) (1.04) 0.02 ------ ------ ------- Effective Income Tax Rate....................... 25.39% 26.68% 22.78% ====== ====== ======= </TABLE> The Company's foreign subsidiaries' undistributed earnings of approximately $166 million at December 31, 1997 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 $55 million India tax net operating loss carryforward at December 31, 1997. 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 $13 million which can be used to offset regular income taxes payable in future years. The AMT credit carryforward has an indefinite carryforward period. 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, 1997, 1996 and 1995, the Company was charged $5.0 million, $5.0 million and $6.6 million, respectively, for all such benefits, including pension expense totaling $1.0 million, $1.0 million and $0.8 million, respectively, by Enron Corp. As of September 30, 1997, the most recent valuation date, the plan net assets of the Enron Corp. defined benefit plan in which the employees of the Company participate exceeded the actuarial present value of projected plan benefit obligations by approximately $110 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 7.25%, 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 medical, life insurance 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 post-retirement 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 Option Plans. The Company has various stock option 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. Options granted under the Plans vest over a period of time based on the nature F-18
51 of the grants and as defined in the individual grant agreements. Terms for options granted under the Plans have not exceeded a maximum term of 10 years. In January 1996, the Company granted 301,500 shares of common stock with a market value of $23.50 per share to certain officers and key employees of the Company under the Plans. Such shares are restricted and vest, subject to continued employment and certain net income performance goals, on the anniversary date of grant which could begin as early as 1998, but in any event no later than January 2002. The fair value of the 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 1997 and 1996 was approximately $1 million per year. The Company accounts for the Plans 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 intends to continue 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 (shares in thousands): <TABLE> <CAPTION> 1997 1996 1995 ----------------- ----------------- ---------------- AVERAGE AVERAGE AVERAGE GRANT GRANT GRANT SHARES PRICE SHARES PRICE SHARES PRICE ------- ------- ------- ------- ------ ------- <S> <C> <C> <C> <C> <C> <C> Outstanding at January 1..... 8,796 $20.70 8,019 $18.61 7,215 $18.15 Granted.................... 3,079 20.18 2,941 24.53 1,650 18.57 Exercised.................. (261) 17.16 (1,989) 17.95 (622) 13.01 Forfeited.................. (1,879) 24.06 (175) 20.28 (224) 19.27 ------- ------- ------ Outstanding at December 31... 9,735 19.99 8,796 20.70 8,019 18.61 ======= ======= ====== Shares Exercisable at December 31................ 5,618 19.70 4,402 19.13 4,716 18.23 ======= ======= ====== Shares Available for Future Grant...................... 2,519 3,741 3,792 ======= ======= ====== Average Fair Value of Shares Granted During Year........ $ 6.96 $ 9.29 $ 6.39 ======= ======= ====== </TABLE> 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 1997, 1996 and 1995, respectively: (1) dividend yield of 0.6%, 0.5% and 0.5%, (2) expected volatility of 27%, 31% and 31%, (3) risk-free interest rate of 6.3%, 5.8% and 7.2%, and (4) expected life of 5.2 years, 5.5 years and 4.1 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. F-19
52 The following table summarizes certain information for the shares outstanding at December 31, 1997 (shares in thousands): <TABLE> <CAPTION> SHARES OUTSTANDING SHARES EXERCISABLE ------------------------------- ------------------ WEIGHTED WEIGHTED WEIGHTED AVERAGE AVERAGE AVERAGE RANGE OF REMAINING GRANT GRANT GRANT PRICES SHARES LIFE PRICE SHARES PRICE - ---------------- ------ --------- -------- ------ -------- <C> <S> <C> <C> <C> <C> <C> $ 9.00 to $13.00 ...................... 477 3 years $ 9.82 477 $ 9.82 13.00 to 18.00 ...................... 1,082 5 17.83 779 17.81 18.00 to 23.00 ...................... 6,484 6 20.08 3,514 20.49 23.00 to 29.00 ...................... 1,692 7 23.86 848 23.72 ----- ----- 9.00 to 29.00 ...................... 9,735 6 19.99 5,618 19.70 ===== ===== </TABLE> The Company's pro forma net income and earnings per share of common stock for 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> 1997 1996 1995 -------------------- -------------------- -------------------- AS AS AS REPORTED PRO FORMA REPORTED PRO FORMA REPORTED PRO FORMA -------- --------- -------- --------- -------- --------- <S> <C> <C> <C> <C> <C> <C> Net Income................ $122.0 $116.7 $140.0 $135.5 $142.1 $139.0 Earnings per Share of Common Stock Basic................... $ .78 $ .74 $ .88 $ .85 $ .89 $ .87 ====== ====== ====== ====== ====== ====== Diluted................. $ .77 $ .74 $ .87 $ .84 $ .88 $ .86 ====== ====== ====== ====== ====== ====== </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. During 1997, 1996 and 1995, the Company purchased or was tendered 4,954,344, 2,383,727 and 762,799 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, 1997, 1996 and 1995. The difference between the cost of the treasury shares and the exercise price of the options, net of federal income tax benefit of $.5 million, $6.1 million and $2.2 million for the years 1997, 1996 and 1995, 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, 1997 and 1996, 4,935,744 and 242,882 shares, respectively, were held in treasury under these authorizations. (See Note 6 "Shareholders' Equity"). Letters Of Credit. At December 31, 1997 and 1996, the Company had letters of credit outstanding totaling approximately $169 million and $213 million, respectively. F-20
53 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. 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. 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 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. CASH FLOW INFORMATION Gains on sales of certain oil and gas reserves and related assets in the amount of $9.3 million, $20.4 million and $62.8 million for the years ended December 31, 1997, 1996 and 1995, respectively, are required by current accounting guidelines to be removed from net income in connection with determining net operating cash inflows while the related proceeds are required to be classified as investing cash flows. The Company believes the proceeds from the sales of reserves and related assets should be considered in analyzing the elements of operating cash flows. The current federal income tax impact of these sales transactions was calculated by the Company to be a benefit of $3.2 million for 1997 and an expense of $8.5 million and $24.4 million for 1996 and 1995, respectively, which entered into the overall calculation of current federal income tax. The Company believes that this federal income tax impact should also be considered in analyzing the elements of the cash flow statement. Non-cash investing and financing activities for 1995 include the issuance by a subsidiary of the Company of redeemable preferred stock with a liquidation/redemption value of $19 million in exchange for certain oil and gas properties. An approximate $7 million step-up in property basis was made relating to deferred tax liabilities associated with the difference between the tax and book bases of acquired properties as required by SFAS No. 109 for a nontaxable business combination. The preferred stock was redeemed in November 1995. Cash paid for interest and income taxes was as follows for the years ended December 31: <TABLE> <CAPTION> 1997 1996 1995 ------- ------- ------- <S> <C> <C> <C> Interest (net of amount capitalized)................... $27,759 $14,237 $11,307 Income taxes........................................... 28,708 42,014 10,140 </TABLE> Included in 1995 income taxes paid is $13 million paid to Enron Corp. for the indemnification of any future liability associated with all federal and state income taxes and certain foreign taxes imposed on the Company for periods prior to the date Enron Corp. reduced its ownership in the Company to below 80%. Pursuant to a new tax allocation agreement (See Note 1 "Summary of Significant Accounting Policies - Income Taxes") such $13 million payment plus interest has been returned to the Company, and the Company has assumed all obligations with respect to the liabilities previously indemnified by Enron Corp. F-21
54 11. BUSINESS SEGMENT INFORMATION The Company's operations are all natural gas and crude oil exploration and production related. Accordingly, such operations are classified as one business segment. Financial information by geographic area is presented below for the years ended December 31, or at December 31: <TABLE> <CAPTION> 1997 1996 1995 ---------- ---------- ---------- <S> <C> <C> <C> Gross Operating Revenues United States................................. $ 725,100 $ 660,804 $ 582,993 Canada........................................ 73,466 63,114 44,585 Other International........................... 106,190 104,226 87,097 ---------- ---------- ---------- Total(1).............................. $ 904,756 $ 828,144 $ 714,675 ========== ========== ========== Operating Income United States................................. $ 138,213 $ 160,109 $ 162,652 Canada........................................ 19,983 12,720 3,442 Other International........................... 34,579 36,001 29,215 ---------- ---------- ---------- Total................................. $ 192,775 $ 208,830 $ 195,309 ========== ========== ========== Identifiable Assets United States................................. $2,036,933 $1,882,900 $1,693,293 Canada........................................ 276,998 236,925 230,498 Other International........................... 409,424 338,528 223,467 ---------- ---------- ---------- Total................................. $2,723,355 $2,458,353 $2,147,258 ========== ========== ========== </TABLE> - --------------- (1) Not deducted are natural gas associated costs of $121,255, $97,496 and $65,973 in 1997, 1996 and 1995, respectively. 12. OTHER INCOME (EXPENSE), NET Other income (expense), net consisted of the following for the years ended December 31: <TABLE> <CAPTION> 1997 1996 1995 ---------- ---------- ---------- <S> <C> <C> <C> Interest Income(1).............................. $ 4,122 $ 2,264 $ 556 Financial Reserve Accruals...................... - (6,897) 379 Litigation Provision............................ (5,800) - - Other, Net...................................... 90 (374) (266) ---------- ---------- ---------- Total................................. $ (1,588) $ (5,007) $ 669 ========== ========== ========== </TABLE> - --------------- (1) Includes $2,549, $403 and $59 from related parties. 13. 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 1997 included a revenue increase of $3.4 million related to change in market value of natural gas price swap options exercisable by a counterparty in 1997 and 1998 and partially offsetting "buy" price swap positions. During 1995, the Company entered into a NYMEX-related natural gas price swap covering 73 TBtu for the year ended December 31, 1996. This swap contained an option to extend the price swap covering 73 TBtu F-22
55 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 $3.4 million revenue increase and a $12 million revenue reduction in 1997 and 1996, respectively, related to these trading activities. In 1995, the Company sold a call option with a notional volume of 50 billion British thermal units ("BBtu") per day at a strike price of $2.10 per MMBtu for each month in the period January 1996 through December 1996. At December 31, 1995, the approximate market value of the outstanding call option was $1.8 million. The Company recognized a $2.6 million revenue reduction in 1995 related to this call option. In the first quarter of 1996, the Company purchased a call option with a notional volume of 50 BBtu per day at a strike price of $2.10 per MMBtu for the period February 1996 through December 1996 for $3.0 million to offset the call option discussed above. The purchase resulted in a $1.2 million revenue reduction recognized in the first quarter of 1996. The Company realized an $11.3 million revenue increase in 1995 related to certain NYMEX-related natural gas commodity price swap transactions with an Enron Corp. affiliated company that were designated for trading purposes in December 1994 and closed in the first quarter of 1995. The following table summarizes the estimated fair value of financial instruments held for trading purposes at yearend and the average during the year: <TABLE> <CAPTION> 1997(1) 1996(1) 1995(1) ------------------- ------------------- ------------------ FAIR AVERAGE FAIR AVERAGE FAIR AVERAGE VALUE FAIR VALUE VALUE FAIR VALUE VALUE FAIR VALUE ------ ---------- ------ ---------- ----- ---------- (IN MILLIONS) (IN MILLIONS) (IN MILLIONS) <S> <C> <C> <C> <C> <C> <C> Options Written.............. $(10.5) $(13.7) $(12.8) $(8.3) $(1.8) $(.3) NYMEX-related Natural Gas Price Swaps................ 4.2 7.1 .8 3.4 - .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, 1997 and 1996, 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, 1997 and 1996, the composite fair value of the 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 enters into NYMEX-related commodity price swaps and costless collars from time to time. 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. The NYMEX-related natural gas commodity price swaps are priced based on a Henry Hub, Louisiana delivery point. The Henry Hub price has historically had a high degree of correlation with a significant portion of the wellhead price received by the Company which has made such transactions effective natural gas price hedges. During December 1995, there was a loss of correlation between the prices paid under the natural gas commodity price swaps and the wellhead natural gas prices ultimately received for a portion of the Company's F-23
56 hedged natural gas production. This loss of correlation resulted in the recognition of a $6 million revenue reduction in 1995. 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 million barrels ("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. At December 31, 1996, the Company had outstanding positions covering notional volumes of approximately 10 TBtu of natural gas for 1997 and approximately 37 TBtu of natural gas for each of the years 1999 and 2000 and approximately 2.1 MMBbl, 1.7 MMBbl and 1.2 MMBbl of crude oil and condensate for the years 1997, 1998 and the period 1999 through 2000, respectively. The fair value of the positions was a negative $27 million at December 31, 1996. The Company closed substantially all of the NYMEX-related natural gas commodity price swaps for 1997 by entering into offsetting positions in the fourth quarter of 1996. At December 31, 1996, the aggregate total of deferred revenue reduction for 1997 and 1998 closed positions was approximately $74 million. The following table summarizes the estimated fair value of financial instruments and related transactions for nontrading activities at December 31, 1997 and 1996: <TABLE> <CAPTION> 1997 1996 1998 ------------------------ ------------------------ ------------------------ CARRYING ESTIMATED CARRYING ESTIMATED CARRYING ESTIMATED AMOUNT FAIR VALUE(1) AMOUNT FAIR VALUE(1) AMOUNT FAIR VALUE(1) -------- ------------- -------- ------------- -------- ------------- (IN MILLIONS) (IN MILLIONS) (IN MILLIONS) <S> <C> <C> <C> <C> <C> <C> Long-Term Debt(2).... $741.3 $744.4 $466.1 $464.5 $289.1 $294.0 Swap Agreements...... 13.3 12.7 32.8 31.0 62.8 58.8 NYMEX-Related Commodity Market Positions.......... (27.4) (31.6) (73.8) (105.5) (5.1) 10.9 </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. 14. CONCENTRATION OF CREDIT RISK Substantially all of the Company's accounts receivable at December 31, 1997 and 1996 result from crude oil and natural gas sales and/or joint interest billings to affiliate and third party companies 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. F-24
57 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" and "proved developed" 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. 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, 1997, 1996 and 1995 were based on studies performed by the engineering staff of the Company for reserves in the United States, Canada, Trinidad and India. Opinions by DeGolyer and MacNaughton, independent petroleum consultants, for the years ended December 31, 1997, 1996 and 1995 covering producing areas containing 54%, 64% and 60%, respectively, of proved reserves, excluding deep Paleozoic methane reserves, of the Company on a net-equivalent-cubic-feet-of-gas basis, indicate that the estimates of proved reserves prepared by the Company's engineering staff for the properties reviewed by DeGolyer and MacNaughton, when compared in total on a net-equivalent-cubic-feet-of-gas basis, do not differ materially from the estimates prepared by DeGolyer and MacNaughton. The deep Paleozoic methane reserves were covered by the opinion of DeGolyer and MacNaughton for the year ended December 31, 1995. Such estimates by DeGolyer and MacNaughton in the aggregate varied by not more than 5% from those prepared by the engineering staff of the Company. All reports by DeGolyer and MacNaughton were developed utilizing geological and engineering data provided by the Company. The presentation of estimated proved reserves excludes, for each of the years presented, those quantities attributable to future deliveries required under a volumetric production payment. In order to calculate such amounts, the Company has assumed that deliveries under the volumetric production payment are made as scheduled at expected British thermal unit factors, and that delivery commitments are satisfied through delivery, as scheduled, of the related volumes. The Company has also presented, as additional information, proved reserves including quantities attributable to future deliveries required under the volumetric production payment. The Company believes F-25
58 that this information is informative to readers of its financial statements as the related oil and gas properties costs and deferred revenue are included in the Company's balance sheets for each of the years presented. This additional information is not required to be presented in accordance with SFAS No. 69; however, the Company believes this additional information is useful in assessing its reserve and financial position on a comprehensive basis. No major discovery or other favorable or adverse event subsequent to December 31, 1997 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, 1997, 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, 1994.............................. 1,307.4 296.6 206.2 29.3 - 1,839.5 Revisions of previous estimates... 10.1 (8.1) 17.5 (29.3) - (9.8) Purchases in place................ 174.8 - - - - 174.8 Extensions, discoveries and other additions....................... 1,391.6(2) 54.8 60.8 75.0 - 1,582.2 Sales in place.................... (38.1) (1.7) - - - (39.8) Production........................ (191.7) (27.7) (39.0) - - (258.4) ------- ------ ------ ------ --- ------- Net proved reserves at December 31, 1995.............................. 2,654.1(2) 313.9 245.5 75.0 - 3,288.5 Additional disclosures: Volumes attributable to volumetric production payment.............. 54.2 - - - - 54.2 ------- ------ ------ ------ --- ------- Net proved reserves at December 31, 1995, including volumes attributable to volumetric production payment................ 2,708.3(2) 313.9 245.5 75.0 - 3,342.7 ======= ====== ====== ====== === ======= 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 Additional disclosures: Volumes attributable to volumetric production payment.............. 37.5 - - - - 37.5 ------- ------ ------ ------ --- ------- Net proved reserves at December 31, 1996, including volumes attributable to volumetric production payment................ 2,784.0(2) 320.9 370.2 199.6 - 3,674.7 ======= ====== ====== ====== === ======= </TABLE> (Table continued on following page) F-26
59 <TABLE> <CAPTION> UNITED STATES CANADA TRINIDAD INDIA OTHER TOTAL ------------- ------ -------- ------ ----- ------- <S> <C> <C> <C> <C> <C> <C> 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 Additional disclosures: Volumes attributable to volumetric production payment.............. 20.8 - - - - 20.8 ------- ------ ------ ------ --- ------- Net proved reserves at December 31, 1997, including volumes attributable to volumetric production payment................ 2,805.6(2) 387.4 328.8 471.6 7.7 4,001.1 ======= ====== ====== ====== === ======= Liquids (MBbl)(3)(4) Net proved reserves at December 31, 1994.............................. 17,787 7,237 4,429 7,585 - 37,038 Revisions of previous estimates... (413) (351) 396 4,874 - 4,506 Purchases in place................ 4,264 - - - - 4,264 Extensions, discoveries and other additions....................... 8,703 729 3,896 - - 13,328 Sales in place.................... (1,241) (9) - - - (1,250) Production........................ (3,701) (1,021) (1,851) (917) - (7,490) ------- ------ ------ ------ --- ------- 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 ======= ====== ====== ====== === ======= Bcf Equivalent (Bcfe) Net proved reserves at December 31, 1994.............................. 1,414.2(5) 339.9 232.8 74.8 - 2,061.7 Revisions of previous estimates... 7.6 (10.2) 19.8 - - 17.2 Purchases in place................ 200.4 - - - - 200.4 Extensions, discoveries and other additions....................... 1,443.8(2) 59.2 84.2 75.0 - 1,662.2 Sales in place.................... (45.5) (1.8) - - - (47.3) Production........................ (213.9) (33.8) (50.1) (5.5) - (303.3) ------- ------ ------ ------ --- ------- Net proved reserves at December 31, 1995.............................. 2,806.6 (2)(5 353.3 286.7 144.3 - 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) ------- ------ ------ ------ --- ------- </TABLE> (Table continued on following page) F-27
60 <TABLE> <CAPTION> UNITED STATES CANADA TRINIDAD INDIA OTHER TOTAL ------------- ------ -------- ------ ----- ------- <S> <C> <C> <C> <C> <C> <C> Net proved reserves at December 31, 1996.............................. 2,920.1 (2)(5 365.3 419.2 264.3 - 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)(5 441.3 370.2 652.0 7.7 4,446.2 Additional disclosures: Volumes attributable to volumetric production payment.............. 20.8 - - - - 20.8 ------- ------ ------ ------ --- ------- Net proved reserves at December 31, 1997, including volumes attributable to volumetric production payment................ 2,995.8(2) 441.3 370.2 652.0 7.7 4,467.0 ======= ====== ====== ====== === ======= Net proved developed reserves at Natural Gas (Bcf) December 31, 1994............... 1,128.2 288.3 206.2 - - 1,622.7 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 Liquids (MBbl)(4) December 31, 1994............... 16,770 7,073 4,429 7,585 - 35,857 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 Bcf Equivalents December 31, 1994............... 1,228.8 330.7 232.8 45.5 - 1,837.8 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 Net proved developed reserves, including amounts attributable to volumetric production payment at Natural Gas (Bcf) December 31, 1994............... 1,199.1 288.3 206.2 - - 1,693.6 December 31, 1995............... 1,272.3 310.1 233.9 - - 1,816.3 December 31, 1996............... 1,363.2 319.5 370.2 124.6 - 2,177.5 December 31, 1997............... 1,369.8 370.9 328.8 286.6 - 2,356.1 </TABLE> - --------------- (1) Billion cubic feet. (2) Includes 1,180 Bcf of proved undeveloped methane reserves contained, along with high concentrations of carbon dioxide and other gases in deep Paleozoic formations in the Big Piney area of Wyoming. The Company is actively pursuing the consummation of a market or markets from several different potential sources to facilitate realizing the value of these reserves. (3) Thousand barrels. (4) Includes crude oil, condensate and natural gas liquids. (5) Excludes approximately 71 Bcfe, 54 Bcfe, 38 Bcfe and 21 Bcfe at December 31, 1994, 1995, 1996 and 1997, respectively, related to a volumetric production payment. F-28
61 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, 1997 and 1996: <TABLE> <CAPTION> 1997 1996 ----------- ----------- <S> <C> <C> Proved Properties.......................................... $ 4,069,914 $ 3,593,230 Unproved Properties........................................ 221,491 159,969 ----------- ----------- Total............................................ 4,291,405 3,753,199 Accumulated depreciation, depletion and amortization....... (1,904,198) (1,653,610) ----------- ----------- Net capitalized costs...................................... $ 2,387,207 $ 2,099,589 =========== =========== </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. 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> 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 ======== ======= ======= ======= ======= ======== 1995 Acquisition Costs of Properties Unproved........................ $ 16,196 $ 4,645 $ - $ - $ 1,482 $ 22,323 Proved.......................... 122,369 116 - 5,000 - 127,485 -------- ------- ------- ------- ------- -------- Total................... 138,565 4,761 - 5,000 1,482 149,808 Exploration Costs................. 47,463 7,197 374 (98) 17,948 72,884 Development Costs................. 217,674 28,611 32,692 16,756 577 296,310 -------- ------- ------- ------- ------- -------- Total................... $403,702 $40,569 $33,066 $21,658 $20,007 $519,002 ======== ======= ======= ======= ======= ======== </TABLE> F-29
62 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> 1997 Operating Revenues Associated Companies........................... $206,738 $15,280 $ - $ - $ 2 $222,020 Trade.......................................... 448,824 58,712 66,000 35,332 21 608,889 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 Associated Companies........................... $253,629 $13,715 $ - $ - $ - $267,344 Trade.......................................... 281,522 48,717 83,536 20,691 - 434,466 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 ======== ======= ======= ======= ======== ======== 1995 Operating Revenues Associated Companies........................... $223,652 $ 6,893 $ - $ - $ - $230,545 Trade.......................................... 122,567 36,815 71,686 15,411 - 246,479 Gains on Sales of Reserves and Related Assets....................................... 62,737 84 - - - 62,821 -------- ------- ------- ------- -------- -------- Total.................................... 408,956 43,792 71,686 15,411 - 539,845 Exploration Expenses, including Dry Hole......... 35,298 3,839 374 (98) 15,542 54,955 Production Costs................................. 63,734 13,825 8,176 10,553 - 96,288 Impairment of Unproved Oil and Gas Properties.... 21,981 1,734 - - - 23,715 Depreciation, Depletion and Amortization......... 180,788 19,533 14,633 335 368 215,657 -------- ------- ------- ------- -------- -------- Income (Loss) before Income Taxes................ 107,155 4,861 48,503 4,621 (15,910) 149,230 Income Tax Provision (Benefit)................... 1,226 1,133 26,677 2,311 (1,335) 30,012 -------- ------- ------- ------- -------- -------- Results of Operations............................ $105,929 $ 3,728 $21,826 $ 2,310 $(14,575) $119,218 ======== ======= ======= ======= ======== ======== </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, 1997. 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. 14 - "Financial Reporting for Segments of a Business Enterprise", but are not part of Disclosures about Oil and Gas Producing Activities as defined in SFAS No. 69. F-30
63 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. The presentation of the standardized measure of discounted future net cash flows and changes therein excludes, for each of the years presented, amounts attributable to future deliveries required under a volumetric production payment at the equivalent wellhead value. In order to calculate such amounts, the Company has assumed that deliveries under the volumetric production payment are made as scheduled and that production costs corresponding to the volumes delivered are incurred by the Company at average rates for the properties subject to the production payment. The Company has also presented, as additional information, the standardized measure of discounted future net cash flows and changes therein including amounts attributable to future deliveries required under the volumetric production payment. The Company believes that this information is informative to readers of its financial statements because the related oil and gas properties costs and deferred revenue are shown in the Company's balance sheets for each of the years presented. This additional information is not required to be presented in accordance with SFAS No. 69; however, the Company believes this additional information is useful in assessing its reserve and financial position on a comprehensive basis. F-31
64 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> 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 Additional disclosures: Amounts attributable to volumetric production payment....................... 18,102 - - - - 18,102 ----------- --------- --------- ---------- ------- ----------- Total discounted future net revenues, including amounts attributable to volumetric production payment............ $ 1,567,821 $ 277,312 $ 147,919 $ 319,728 $ 5,776 $ 2,318,556 =========== ========= ========= ========== ======= =========== 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 Additional disclosures: Amounts attributable to volumetric production payment....................... 75,081 - - - - 75,081 ----------- --------- --------- ---------- ------- ----------- Total discounted future net revenues, including amounts attributable to volumetric production payment............ $ 2,566,850 $ 225,758 $ 156,838 $ 194,185 $ - $ 3,143,631 =========== ========= ========= ========== ======= =========== 1995 Future cash inflows(1)....................... $ 3,996,029 $ 502,803 $ 395,328 $ 396,130 $ - $ 5,290,290 Future production costs...................... (747,064) (203,906) (152,287) (202,410) - (1,305,667) Future development costs..................... (297,859) (7,153) (3,610) (13,500) - (322,122) ----------- --------- --------- ---------- ------- ----------- Future net cash flows before income taxes.... 2,951,106 291,744 239,431 180,220 - 3,662,501 Future income taxes.......................... (695,843) (46,310) (105,188) (81,349) - (928,690) ----------- --------- --------- ---------- ------- ----------- Future net cash flows........................ 2,255,263 245,434 134,243 98,871 - 2,733,811 Discount to present value at 10% annual rate....................................... (1,015,123) (68,861) (19,217) (45,470) - (1,148,671) ----------- --------- --------- ---------- ------- ----------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves................................... 1,240,140 176,573 115,026 53,401 - 1,585,140 Additional disclosures: Amounts attributable to volumetric production payment....................... 35,957 - - - - 35,957 ----------- --------- --------- ---------- ------- ----------- Total discounted future net revenues, including amounts attributable to volumetric production payment............ $ 1,276,097 $ 176,573 $ 115,026 $ 53,401 $ - $ 1,621,097 =========== ========= ========= ========== ======= =========== </TABLE> - --------------- (1) Based on year end market prices determined at the point of delivery from the producing unit. F-32
65 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, 1997. <TABLE> <CAPTION> UNITED STATES CANADA TRINIDAD INDIA OTHER TOTAL ------ ------ -------- ----- ----- ----- <S> <C> <C> <C> <C> <C> <C> December 31, 1994........................ $ 962,805(1) $156,941 $103,430 $ 20,818 $ - $1,243,994 Sales and transfers of oil and gas produced, net of production costs.... (268,463) (29,883) (63,510) (4,858) - (366,714) Net changes in prices and production costs................................ 12,079 (5,698) (37,035) 7,857 - (22,797) Extensions, discoveries, additions and improved recovery net of related costs................................ 376,474(2) 38,028 53,674 46,180 - 514,356 Development costs incurred............. 29,100 2,600 1,800 - - 33,500 Revisions of estimated development costs................................ 920 139 28,771 4,500 - 34,330 Revisions of previous quantity estimates............................ 5,694 (5,217) 10,142 (29) - 10,590 Accretion of discount.................. 97,248 17,483 17,412 2,857 - 135,000 Net change in income taxes............. (132,614) 10,592 (8,048) (28,127) - (158,197) Purchases of reserves in place......... 193,711 - - - - 193,711 Sales of reserves in place............. (54,441) (569) - - - (55,010) Changes in timing and other............ 17,627 (7,843) 8,390 4,203 - 22,377 ---------- -------- -------- -------- ------ ---------- December 31, 1995........................ 1,240,140(1)(2) 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)(2) 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)(2) 277,312 147,919 319,728 5,776 2,300,454 Additional disclosures: Amounts attributable to volumetric production payment................... 18,102 - - - - 18,102 ---------- -------- -------- -------- ------ ---------- Total discounted future net revenues relating to proved oil and gas reserves, including amounts attributable to volumetric production payment, at December 31, 1997........ $1,567,821 $277,312 $147,919 $319,728 $5,776 $2,318,556 ========== ======== ======== ======== ====== ========== </TABLE> - --------------- (1) Excludes $60,269, $35,957, $75,081 and $18,102 at December 31, 1994, 1995, 1996 and 1997 respectively, related to a volumetric production payment. (2) Includes approximately $77,500, $344,300 and $85,700 discounted before income taxes, in 1995, 1996 and 1997 respectively, related to the reserves in the Big Piney deep Paleozoic formations. F-33
66 UNAUDITED QUARTERLY FINANCIAL INFORMATION <TABLE> <CAPTION> QUARTER ENDED ----------------------------------------- MARCH 31 JUNE 30 SEPT. 30 DEC. 31 -------- -------- -------- -------- <S> <C> <C> <C> <C> 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 ======== ======== ======== ======== Earnings 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 ======== ======== ======== ======== Earnings 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 ======== ======== ======== ======== 1995 Net Operating Revenues..................... $155,362 $183,974 $153,006 $156,360 ======== ======== ======== ======== Operating Income........................... $ 42,829 $ 73,374 $ 37,925 $ 41,181 ======== ======== ======== ======== Income before Income Taxes................. $ 39,500 $ 71,331 $ 33,344 $ 39,879 Income Tax Provision....................... 9,875 23,193 376 8,492 -------- -------- -------- -------- Net Income................................. $ 29,625 $ 48,138 $ 32,968 $ 31,387 ======== ======== ======== ======== Earnings per Share of Common Stock Basic.................................... $ .19 $ .30 $ .21 $ .20 ======== ======== ======== ======== Diluted.................................. $ .18 $ .30 $ .20 $ .19 ======== ======== ======== ======== Average Number of Common Shares Basic.................................... 159,972 159,965 159,916 159,817 ======== ======== ======== ======== Diluted.................................. 160,677 161,494 161,260 161,028 ======== ======== ======== ======== </TABLE> F-34
67 SCHEDULE II ENRON OIL & GAS COMPANY SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 (IN THOUSANDS) <TABLE> <CAPTION> ======================================================================================================== COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - -------------------------------------------------------------------------------------------------------- ADDITIONS DEDUCTIONS FOR BALANCE AT CHARGED TO PURPOSE FOR BALANCE AT BEGINNING OF COSTS AND WHICH RESERVES END OF DESCRIPTION YEAR EXPENSES WERE CREATED YEAR - -------------------------------------------------------------------------------------------------------- <S> <C> <C> <C> <C> 1997 Reserves deducted from assets to which they apply - Revaluation of Accounts Receivable........ $7,030 $ - $ 5 $7,025 ====== ====== ====== ====== 1996 Reserves deducted from assets to which they apply - Revaluation of Accounts Receivable........ $2,571 $6,897 $2,438 $7,030 ====== ====== ====== ====== 1995 Reserves deducted from assets to which they apply - Revaluation of Accounts Receivable........ $1,022 $1,549 $ - $2,571 ====== ====== ====== ====== Litigation Reserve(a)....................... $2,000 $ (379)(b) $1,621 $ - ====== ====== ====== ====== </TABLE> - ------------------ (a) Included in Other Liabilities in the consolidated balance sheets. (b) Includes reversal of prior year provision in excess of requirement. S-1
68 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> 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 and February 13, 1997 (Exhibit 3.2 to the Company's Annual Report on Form 10-K for the year ended December 31, 1996). 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. 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. 10.3 - 1995 Tax Allocation Agreement, entered into effective as of December 14, 1995, between Enron Corp., Enron Oil & Gas Company, and the subsidiaries of Enron Oil & Gas Company listed therein as additional parties (Exhibit 10.3 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). </TABLE> E-1
69 <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). 10.14(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). 10.28 - Enron Executive Supplemental Survivor Benefits Plan Effective January 1, 1987 (Exhibit 10.51 to Form S-1). </TABLE> E-2
70 <TABLE> <CAPTION> EXHIBIT NUMBER DESCRIPTION ------- ----------- <C> <S> 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). *10.34(c) - Second Amendment to Enron Oil & Gas Company 1992 Stock Plan (As Amended and Restated Effective December 14, 1994). 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). 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). </TABLE> E-3
71 <TABLE> <CAPTION> EXHIBIT NUMBER DESCRIPTION ------- ----------- <C> <S> 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). *10.60 - Services Agreement, dated January 1, 1997, between Enron Corp. and Enron Oil & Gas Company. </TABLE> E-4
72 <TABLE> <CAPTION> EXHIBIT NUMBER DESCRIPTION ------- ----------- <C> <S> 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. *10.63(a) - Enron Oil & Gas Company 1996 Deferral Plan. *10.63(b) - First Amendment to Enron Oil & Gas Company 1996 Deferral Plan, dated effective as of December 9, 1997. *10.64 - Executive Employment Agreement between Enron Oil & Gas Company and Mark G. Papa, effective as of November 1, 1997. *21 - List of subsidiaries. *23.1 - Consent of DeGolyer and MacNaughton. *23.2 - Opinion of DeGolyer and MacNaughton dated January 13, 1998. *23.3 - Consent of Arthur Andersen LLP. *24 - Powers of Attorney. *27 - Financial Data Schedule. </TABLE> E-5
73 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 13th day of March, 1998. 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 13th day of March, 1998. <TABLE> <CAPTION> SIGNATURE TITLE --------- ----- <C> <S> /s/ FORREST E. HOGLUND Chairman of the Board and Chief Executive - ----------------------------------------------------- Officer and Director (Principal Executive (Forrest E. Hoglund) Officer) /s/ WALTER C. WILSON Senior Vice President and Chief Financial - ----------------------------------------------------- Officer (Principal Financial Officer) (Walter C. Wilson) /s/ BEN B. BOYD Vice President and Controller (Principal - ----------------------------------------------------- Accounting Officer) (Ben B. Boyd) FRED C. ACKMAN * Director - ----------------------------------------------------- (Fred C. Ackman) JAMES V. DERRICK, JR. * Director - ----------------------------------------------------- (James V. Derrick, Jr.) 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>
74 INDEX TO EXHIBITS <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 and February 13, 1997 (Exhibit 3.2 to the Company's Annual Report on Form 10-K for the year ended December 31, 1996). 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. 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. 10.3 - 1995 Tax Allocation Agreement, entered into effective as of December 14, 1995, between Enron Corp., Enron Oil & Gas Company, and the subsidiaries of Enron Oil & Gas Company listed therein as additional parties (Exhibit 10.3 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). 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). </TABLE>
75 <TABLE> <CAPTION> EXHIBIT NUMBER DESCRIPTION ------- ----------- <C> <S> 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). 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). </TABLE>
76 <TABLE> <CAPTION> EXHIBIT NUMBER DESCRIPTION ------- ----------- <C> <S> 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). *10.34(c) - Second Amendment to Enron Oil & Gas Company 1992 Stock Plan (As Amended and Restated Effective December 14, 1994). 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). 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). </TABLE>
77 <TABLE> <CAPTION> EXHIBIT NUMBER DESCRIPTION ------- ----------- <C> <S> 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). *10.60 - Services Agreement, dated January 1, 1997, between Enron Corp. and Enron Oil & Gas Company. 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). </TABLE>
78 <TABLE> <CAPTION> EXHIBIT NUMBER DESCRIPTION ------- ----------- <C> <S> *10.62 - Stock Restriction and Registration Rights Agreement, dated December 9, 1997, between Enron Corp. and Enron Oil & Gas Company. *10.63(a) - Enron Oil & Gas Company 1996 Deferral Plan. *10.63(b) - First Amendment to Enron Oil & Gas Company 1996 Deferral Plan, dated effective as of December 9, 1997. *10.64 - Executive Employment Agreement between Enron Oil & Gas Company and Mark G. Papa, effective as of November 1, 1997. *21 - List of subsidiaries. *23.1 - Consent of DeGolyer and MacNaughton. *23.2 - Opinion of DeGolyer and MacNaughton dated January 13, 1998. *23.3 - Consent of Arthur Andersen LLP. *24 - Powers of Attorney. *27 - Financial Data Schedule. </TABLE>