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, 1996 [ ] 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> <C> <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 ------------------- --------------------- <C> <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 28, 1997 was $1,461,482,413. As of March 1, 1997, there were 158,792,746 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 6, 1997 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 Other Natural Gas Marketing Volumes and Prices.............. 8 Competition................................................. 8 Regulation.................................................. 8 Relationship Between the Company and Enron Corp............. 11 Other Matters............................................... 13 Current Executive Officers of the Registrant................ 14 Item 2. Properties.................................................. 15 Oil and Gas Exploration and Production Properties and Reserves.................................................... 15 Item 3. Legal Proceedings........................................... 17 Item 4. Submission of Matters to a Vote of Security Holders......... 18 PART II Item 5. Market for the Registrant's Common Equity and Related Shareholder Matters......................................... 18 Item 6. Selected Financial Data..................................... 19 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.................................................. 20 Item 8. Financial Statements and Supplementary Data................. 26 Item 9. Disagreements on Accounting and Financial Disclosure........ 26 PART III Item 10. Directors and Executive Officers of the Registrant.......... 27 Item 11. Executive Compensation...................................... 27 Item 12. Security Ownership of Certain Beneficial Owners and Management.................................................. 27 Item 13. Certain Relationships and Related Transactions.............. 27 PART IV Item 14. Financial Statements and Financial Statement Schedule, Exhibits and Reports on Form 8-K............................ 27 </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, 1996, the Company's estimated net proved natural gas reserves were 3,675 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 55 million barrels ("MMBbl"). (See "Supplemental Information to Consolidated Financial Statements"). At such date, approximately 74% of the Company's reserves (on a natural gas equivalent basis) was located in the United States, 9% in Canada, 10% in Trinidad and 7% in India. As of December 31, 1996, the Company employed approximately 800 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 refocused its 1996 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. Enron Corp. currently owns 53% 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 79% of the Company's United States reserves (on a natural gas equivalent basis) and 81% of the Company's United States net natural gas deliverability as of December 31, 1996 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, Mississippi, California and Kansas. At December 31, 1996, 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. The Company also has natural gas and crude oil producing properties located in Western Canada, primarily in the provinces of Alberta, Saskatchewan and Manitoba. 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 248,400 net acres under lease directly within field limits. The Company operates approximately 560 natural gas wells in this area in which it owns an 84% average working interest. Deliveries from the area net to the Company averaged 112 million cubic feet ("MMcf") per day of natural gas and 2.4 thousand barrels ("MBbl") per day of crude oil, condensate, and natural gas liquids in 1996. At December 31, 1996, 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 65% of the Company's Big Piney proved developed reserves. The Company drilled 55 wells in the Big Piney area in 1996 and anticipates an active drilling program will continue for several years. In 1995, the Company 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. Effective October 1, 1996, the Company acquired all of the South Texas Lobo Trend properties of another operator. The acquisition also included producing properties in Atascosa and Kleberg counties. Net production from the acquired properties as of December 31, 1996 was 23 million cubic feet of natural gas equivalent per day, located on more than 65,000 net leasehold and mineral fee acres. The Company now operates approximately 330 wells in the South Texas area. Production is primarily from the Upper Wilcox and Lobo sands at depths ranging from 5,000 to 13,000 feet. The Company has approximately 200,000 net 2
5 leasehold acres and more than 40,000 net mineral fee acres in this area. Natural gas deliveries net to the Company averaged approximately 149 MMcf per day in 1996. At December 31, 1996, natural gas deliverability from this area net to the Company was approximately 180 MMcf per day. The Company drilled 50 wells in the South Texas area in 1996 and participated in sizable 3-D seismic acquisition efforts. 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, and the North Milton field, located in northern Harris County. 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 52 wells in the East Texas area in 1996 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 1997. At December 31, 1996, deliverability from the East Texas area was approximately 50 MMcf per day of natural gas with 1.8 MBbl per day of crude oil, condensate and natural gas liquids both net to the Company. Offshore Gulf of Mexico Area. During 1996, the Company participated in four lease sales (two Texas State and two Federal) offering leases in the Gulf of Mexico and acquired approximately 127,700 net acres (47 leases). Such leases acquired included the Company's first acreage in the deeper waters (600 feet to 2,700 feet water depths) in the Gulf of Mexico consisting of seven leases in the Garden Banks and East Breaks areas. At December 31, 1996, the Company held an interest in 184 blocks in the Offshore Gulf of Mexico area totaling approximately 504,000 net acres. Of the 184 blocks, 132 are operated by the Company. These interests are located predominantly in federal waters offshore Texas and Louisiana. Natural gas deliveries from this area averaged 125 MMcf per day during 1996 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. The Company is currently evaluating development plans for Eugene Island Block 135, and anticipates initial production to begin flowing from this discovery and subsequent development wells in the third quarter of 1997. Deliverability from this area at December 31, 1996 was approximately 130 MMcf per day net to the Company sourced principally as noted above. The Company has maintained an active drilling program in the Offshore Gulf of Mexico area during 1996 and anticipates a similar program to continue for several years. Canyon/Strawn Trend Area. The Company's activities in this area have been concentrated in Crockett, Terrell and Val Verde Counties, Texas where the Company drilled 51 natural gas wells during 1996. The Company holds approximately 57,000 net acres and now operates approximately 170 natural gas wells in this area in which it owns a 75% average working interest. Production is from the Canyon sands and Strawn limestone at depths from 5,500 to 12,500 feet. During April 1996, the Company sold 311 Sutton County wells with daily production of 15 MMcf per day. At December 31, 1996, natural gas deliverability net to the Company was approximately 36 MMcf per day. The Company plans an aggressive program on several new prospects, including the potential for some horizontal drilling, in 1997. Sand Tank Area. The Sand Tank area located in Eddy County, New Mexico produces from the Chester, Morrow, and Atoko formations. In 1996, the Company acquired 85 square miles of 3-D seismic and drilled seven wells, adding natural gas deliverability of 16 MMcf per day. The Company holds 11,500 net acres and has an average working interest of approximately 60%. Several wells are planned in 1997 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 1996, deliveries net to the Company averaged 24 MMcf per day of natural gas and approximately 2.3 MBbl per day of crude oil, condensate and natural gas liquids. At December 31, 1996, deliverability net to the Company was approximately 21 MMcf per day of natural gas and 2.2 MBbl per day of crude oil, condensate and natural gas liquids. The Company holds approximately 36,000 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. 3
6 Vernal Area. In the Vernal area, located primarily in Uintah County, Utah, the Company operates approximately 220 producing wells and presently controls approximately 73,400 net acres. In 1996, natural gas deliveries net to the Company from the Vernal area averaged 20 MMcf per day which also represents deliverability at December 31, 1996. 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. The Company produces natural gas from seven major areas and crude oil from four major areas. The Sandhills field in southwestern Saskatchewan is the largest single producing area where 70 wells were drilled in 1996 resulting in deliverability net to the Company from the field of approximately 37 MMcf per day at December 31, 1996. Canadian natural gas deliverability net to the Company at December 31, 1996 was approximately 102 MMcf per day, and the Company held approximately 321,000 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 conducting exploration in selected other international areas. Properties offshore Trinidad and India comprised 100% of the Company's proved reserves and production outside of North America at year end 1996. 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 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 1996, deliveries net to the Company averaged 124 MMcf per day of natural gas and 5.2 MBbl per day of crude oil and condensate. At December 31, 1996, natural gas deliverability net to the Company was approximately 182 MMcf per day and 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 may occur in late 1997 or early 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 initiated a development plan for the Tapti Block accumulations and expects production to begin during the first half of 1997. The 106,000 acre Panna Block and the 192,000 acre Mukta Block are partially developed with 24 wells producing from five production platforms located in the Panna and Mukta fields. The fields were producing approximately 3.3 MBbl per day of crude oil net to the Company as of December 31, 1996; all associated natural gas is currently being flared. The Company intends to continue development of the accumulations and to expand processing capacity to allow crude oil production at full deliverability as well as to permit natural gas sales. Venezuela. The Company was awarded exploration, exploitation and development rights for a block offshore the eastern state of Soucre, Venezuela in early 1996. The Company signed agreements with the government of Venezuela and partners associated with a concession awarded in the Gulf of Paria East. The 4
7 Company holds an initial 90 percent working interest in the joint venture. A 3-D seismic data gathering project is currently underway and initial drilling is anticipated in 1998. 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. In June 1996, the Company signed a cooperative agreement with the Chinese National Petroleum Corporation ("CNPC") to evaluate the potential for increasing production of crude oil in the Sichuan Basin of the People's Republic of China. If successful, the project could culminate in a joint development agreement with CNPC covering the Chuanzhong Block. The Company has also completed the extension and enhancement of an existing Memorandum of Understanding with Uzbekneftigaz covering the pursuit of marketing opportunities for proven hydrocarbon reserves in eleven fields in the Surhandarya and Bukhara regions of Uzbekistan as well as the fields joint venture development. The Company is also participating in discussions concerning the potential for conventional crude oil and natural gas development opportunities in Mozambique and Algeria, as well as other opportunities in Trinidad, India and Venezuela. The Company continues evaluation and assessment of its international opportunity portfolio in the coalbed methane recovery arena, including projects in South Wales in the U.K., the Lorraine Basin in France, Galilee Basin in Australia and the San Jiao area and Hedong Basin in China. 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 contract, 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 20% 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 30% 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. In addition, EOGM has purchased and constructed several small gathering systems in order to facilitate its entry into the gathering business on a limited basis. Both the Company and EOGM utilize other short and long-term hedging and trading mechanisms including sales and purchases utilizing NYMEX-related commodity market transactions. These marketing activities have provided an effective balance in managing a portion of the Company's exposure to commodity price risks for both natural gas and crude oil and condensate wellhead prices. (See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Hedging Transactions.") 5
8 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 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 $7 million, respectively, with offsetting decreases in 1998 and 1999 versus that anticipated under the Cogen Contracts. 6
9 WELLHEAD VOLUMES AND PRICES, AND LEASE AND WELL EXPENSES The following table sets forth certain information regarding the Company's wellhead volumes of and average prices for natural gas per thousand cubic feet ("Mcf"), crude oil and condensate, and natural gas liquids per barrel ("Bbl"), and average lease and well expenses per thousand cubic feet equivalent ("Mcfe" - natural gas equivalents are determined using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of crude oil and condensate or natural gas liquids) delivered during each of the three years in the period ended December 31, 1996: <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, ------------------------------ 1996 1995 1994 ------ ------ ------ <S> <C> <C> <C> VOLUMES (PER DAY) Natural Gas (MMcf) United States(1)....................................... 608 560 614 Canada................................................. 98 76 72 Trinidad............................................... 124 107 63 ------ ------ ------ Total............................................. 830 743 749 ====== ====== ====== Crude Oil and Condensate (MBbl) United States.......................................... 9.2 9.1 8.0 Canada................................................. 2.4 2.4 2.0 Trinidad............................................... 5.2 5.1 2.5 India.................................................. 2.8 2.5 .1 ------ ------ ------ Total............................................. 19.6 19.1 12.6 ====== ====== ====== Natural Gas Liquids (MBbl) United States.......................................... 1.3 1.0 .3 Canada................................................. 1.2 .4 .4 ------ ------ ------ Total............................................. 2.5 1.4 .7 ====== ====== ====== AVERAGE PRICES Natural Gas ($/Mcf) United States(2)....................................... $ 2.04 $ 1.39 $ 1.71 Canada................................................. 1.15 .97 1.42 Trinidad............................................... 1.00 .97 .93 Composite......................................... 1.78 1.29 1.62 Crude Oil and Condensate ($/Bbl) United States.......................................... $21.88 $17.32 $16.06 Canada................................................. 18.01 16.22 14.05 Trinidad............................................... 19.76 16.07 15.50 India.................................................. 20.17 16.81 15.70 Composite......................................... 20.60 16.78 15.62 Natural Gas Liquids ($/Bbl) United States.......................................... $14.67 $11.88 $12.45 Canada................................................. 9.14 9.74 8.45 Composite......................................... 11.99 11.31 9.90 LEASE AND WELL EXPENSES ($/MCFE) United States............................................. $ .19 $ .19 $ .19 Canada.................................................... .34 .35 .34 Trinidad.................................................. .16 .15 .17 India..................................................... .99 1.25(3) .13(3) Composite......................................... .22 .22 .20 </TABLE> - --------------- (1) Includes 48 MMcf per day in 1996, 1995 and 1994 delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended. (2) Includes an average equivalent wellhead value of $1.17 per Mcf in 1996, $.80 per Mcf in 1995 and $1.27 per Mcf in 1994 for the volumes described in note (1), net of transportation costs. (3) Based on expense estimates for nine days of production for 1994. Expenses for 1995 include certain nonrecurring startup costs. 7
10 OTHER NATURAL GAS MARKETING VOLUMES AND PRICES The following table sets forth certain information regarding the Company's volumes of natural gas delivered under other marketing and volumetric production payment arrangements, and resulting average per unit gross revenue and per unit amortization of deferred revenues along with associated costs during each of the three years in the period ended December 31, 1996. (See "Marketing" for a discussion of other natural gas marketing arrangements and agreements). <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, ----------------------- 1996 1995 1994 ----- ----- ----- <S> <C> <C> <C> Volume (MMcf per day)(1).................................... 285 264 324 Average Gross Revenue ($/Mcf)(2)............................ $2.24 $1.88 $2.38 Associated Costs ($/Mcf)(3)(4).............................. 2.07 1.51 2.06 ----- ----- ----- Margin ($/Mcf).............................................. $ .17 $ .37 $ .32 ===== ===== ===== </TABLE> - --------------- (1) Includes 48 MMcf per day in 1996, 1995 and 1994 delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended. (2) Includes per unit deferred revenue amortization for the volumes detailed in note (1) at an equivalent of $2.46 per Mcf ($2.36 per million British thermal units ("MMBtu") in 1996, 1995 and 1994. (3) Includes an average value of $2.12 per Mcf in 1996, $1.57 per Mcf in 1995 and $1.92 per Mcf in 1994, for the volumes detailed in note (1) including average wellhead value and any transportation costs and exchange differentials. (4) Including transportation and exchange differentials. 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. 8
11 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 pipelines' 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. Appeals are pending and these orders may be amended or reversed in whole or in part. 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. With Order No. 636 and pending ongoing FERC reviews of individual pipeline restructurings, subject to court review, it is difficult to predict with precision its effects. In many instances, however, Order No. 636 has substantially reduced or brought to an end interstate pipelines' traditional roles 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. 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, 9
12 environmental, and in some circumstances, non-discriminatory 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. 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. 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 initiated a proceeding in which it intends to evaluate its current regulatory treatment of pipeline facilities constructed in offshore federal waters. The ultimate outcome of such proceeding cannot be predicted at this time, but it is possible that it could result in more active oversight by the FERC of such offshore facilities. 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, federal legislation addressing pipeline safety issues was considered during 1994 and 1995, which, if enacted, would have included a federal "one-call" notification system and certain new facilities specifications applicable to certain new construction. Similar "one-call" legislation has been reintroduced in the U.S. Congress. The Company cannot predict what effect, if any, the adoption of this or other additional pipeline safety legislation might have on its operations, but does not believe that any adverse effect would be material. 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 pending before 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, provincial and municipal legislation and regulations governing land tenure, royalties, production rates, pricing, environmental 10
13 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 activities in other selected international areas. RELATIONSHIP BETWEEN THE COMPANY AND ENRON CORP. Ownership of Common Stock. Enron Corp. owns 53% of the outstanding shares of common stock of the Company. Through its ability to elect all of the directors of the Company, Enron Corp. has the ability to control all matters relating to the management and policies of the Company, including any determination with respect to acquisition or disposition of Company assets, future issuance of common stock or other securities of the Company and any dividends payable on the common stock. Enron Corp. also has the ability to control the Company's exploration, development, acquisition and operating expenditure plans. There is no agreement between Enron Corp. and the Company that would prevent Enron Corp. from acquiring additional shares of common stock of the Company. The Company has filed a registration statement which would allow Enron Corp. to sell from time to time up to 4.94 million shares of common stock of the Company in secondary offerings of outstanding shares. 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 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 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%. The Company does not believe that the cessation of consolidated tax reporting with Enron Corp., the termination of the tax allocation agreement concurrent with deconsolidation and the signing of the new tax allocation agreement with Enron Corp. will have a material adverse effect on its financial condition or results of operations. Contractual Arrangements. The Company entered into a Services Agreement (the "Services Agreement") with Enron Corp. effective January 1, 1994, pursuant to which Enron Corp. provides various services, such as maintenance of certain employee benefit plans, provision of telecommunications and computer services, lease of office space and the provision of 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 $7.5 million in 1996 and $7 million for 1995. 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, but such increase will not exceed 7.5% per year. The Services Agreement is for an initial term of five years through December 1998 and will continue thereafter until terminated by either party. 11
14 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. Conflicts of Interest. The nature of the respective businesses of the Company and Enron Corp. is such as to potentially give rise to conflicts of interest between the companies. Conflicts could arise, for example, with respect to transactions involving purchases, sales and transportation of natural gas and other business dealings between the Company and Enron Corp., potential acquisitions of businesses or crude oil and natural gas properties, the issuance of additional shares of voting securities, the election of directors or the payment of dividends by the Company. Circumstances may also arise that would cause Enron Corp. to engage in the exploration for and/or development and production of natural gas and crude oil in competition with the Company. For example, opportunities might arise which would require financial resources greater than those available to the Company, which are located in areas or countries in which the Company does not intend to operate or which involve properties that the Company would be unwilling to acquire. Also, Enron Corp. might acquire a competing crude oil and natural gas business as part of a larger acquisition. In addition, as part of Enron Corp.'s strategy of securing supplies of natural gas or capital, Enron Corp. may from time to time acquire producing properties or interests in entities owning producing properties, and thereafter engage in exploration, development and production activities with respect to such properties or indirectly engage in such activities through such companies. Enron Corp. provides or arranges financing, including debt or equity financing, for exploration and production companies that compete with the Company. In connection with such activities, Enron Corp. may make investments in the debt or equity of such companies. In its financing activities, Enron Corp. 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 lending activities, Enron Corp. 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. Such acquisition, exploration, development and production activities may directly or indirectly compete with the Company's business. There can be no assurances that Enron Corp. will not engage directly or indirectly through entities other than the Company in the natural gas and crude oil exploration, development and production business in competition with the Company. In connection with the finance and trading business of Enron Capital & Trade Resources Corp. ("ECT"), a wholly-owned subsidiary of Enron Corp., affiliates of ECT may make investments in the debt or equity of companies engaged in the exploration for, and the development, production and marketing of, natural gas and crude oil. Conflicts may arise between these companies and the Company, and Enron Corp. will be required to resolve such conflicts in a manner that is consistent with its fiduciary and contractual duties to other investors in these companies and its fiduciary duties to the Company. 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, the financing of exploration and development efforts by the Company, and the provision of certain corporate services. (See "Marketing" and the Consolidated Financial Statements and notes thereto). The Company believes that its existing transactions and agreements with Enron Corp. have been at least as favorable to the Company as could be obtained from third parties, and the 12
15 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 13% from 1993 to 1994 and 20% from 1994 to 1995, the average North America wellhead natural gas price received by the Company increased 43% from 1995 to 1996. 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 are scheduled to commence in early 1997 and under the terms of the Production Sharing Contract, the price of such deliveries, when initiated, is to be 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. To mitigate the risk of market price fluctuations, the Company from time to time engages in certain price risk management activities to hedge commodity prices associated with a portion of the Company's sales and purchases of natural gas and crude oil. (See "Management's Discussion and Analysis of Financial Condition and Results of Operations"). 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 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 $46 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 13
16 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. CURRENT EXECUTIVE OFFICERS OF THE REGISTRANT The current executive officers of the Company and their names and ages are as follows: <TABLE> <CAPTION> NAME AGE POSITION ---- --- -------- <S> <C> <C> Forrest E. Hoglund..................... 63 Chairman of the Board and Chief Executive Officer; Director Mark G. Papa........................... 50 President and President - North American Operations Dennis M. Ulak......................... 43 President - International Operations Barry Hunsaker, Jr..................... 46 Senior Vice President and General Counsel Walter C. Wilson....................... 54 Senior Vice President and Chief Financial Officer Ben B. Boyd............................ 55 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 Texas Commerce Bancshares, Inc. Mark G. Papa was elected President of the Company in December 1996 and has been President - North American 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. Dennis M. Ulak has been President - International Operations since January 1996 with responsibility for activities outside North America. Mr. Ulak also serves as President and Chief Operating 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. Barry Hunsaker, Jr. has been Senior Vice President and General Counsel since he joined the Company in May 1996. Prior to joining the Company, Mr. Hunsaker was a partner in the law firm of Vinson & Elkins L.L.P. Walter C. Wilson joined the Company in November 1987 and has been Senior Vice President and Chief Financial Officer since May 1991. Ben B. Boyd joined the Company in March 1984 and has been Vice President and Controller since March 1991. 14
17 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. 15
18 Acreage. The following table summarizes the Company's developed and undeveloped acreage at December 31, 1996. 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............... 13,030 8,341 658,089 654,054 671,119 662,395 Offshore Gulf of Mexico................ 310,886 147,446 463,408 356,346 774,294 503,792 Texas.................... 285,706 198,579 232,543 205,704 518,249 404,283 Wyoming.................. 154,736 111,979 302,474 235,762 457,210 347,741 Oklahoma................. 176,218 94,222 68,270 58,944 244,488 153,166 New Mexico............... 72,278 35,328 82,962 48,611 155,240 83,939 Utah..................... 57,819 46,511 32,437 26,939 90,256 73,450 Kansas................... 10,418 8,875 15,974 14,670 26,392 23,545 Colorado................. 8,313 1,219 26,485 13,697 34,798 14,916 Mississippi.............. 1,942 1,853 12,695 12,498 14,637 14,351 Louisiana................ 6,054 5,909 1,360 1,295 7,414 7,204 Pennsylvania............. 1,443 962 6,749 4,538 8,192 5,500 Other.................... 5,385 3,352 7,719 5,741 13,104 9,093 --------- --------- ---------- --------- ---------- --------- Total............ 1,104,228 664,576 1,911,165 1,638,799 3,015,393 2,303,375 Canada Alberta.................. 365,797 174,932 196,936 157,639 562,733 332,571 Saskatchewan............. 180,623 156,548 184,504 160,013 365,127 316,561 Manitoba................. 11,371 9,622 4,213 3,333 15,584 12,955 British Columbia......... 656 164 - - 656 164 --------- --------- ---------- --------- ---------- --------- Total Canada..... 558,447 341,266 385,653 320,985 944,100 662,251 Other International Australia................ - - 7,680,000 3,840,000 7,680,000 3,840,000 China.................... - - 1,208,805 604,403 1,208,805 604,403 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 United Kingdom........... - - 173,600 86,000 173,600 86,000 --------- --------- ---------- --------- ---------- --------- Total Other International... 102,500 33,480 10,234,616 5,277,015 10,337,116 5,310,495 --------- --------- ---------- --------- ---------- --------- Total.......... 1,765,175 1,039,322 12,531,434 7,236,799 14,296,609 8,276,121 ========= ========= ========== ========= ========== ========= </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, 1996. Gross gas and oil wells include 200 with multiple completions. <TABLE> <CAPTION> PRODUCTIVE WELLS ---------------- GROSS NET ------ ------ <S> <C> <C> Gas......................................................... 5,021 3,427 Oil......................................................... 886 516 ----- ----- Total............................................. 5,907 3,943 ===== ===== </TABLE> 16
19 Drilling and Acquisition Activities. During the years ended December 31, 1996, 1995 and 1994 the Company spent approximately $599 million, $514 million and $494 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, ------------------------------------------------ 1996 1995 1994 -------------- -------------- -------------- GROSS NET GROSS NET GROSS NET ----- ------ ----- ------ ----- ------ <S> <C> <C> <C> <C> <C> <C> Development Wells Completed North America Gas....................................... 396 325.04 334 251.06 554 430.73 Oil....................................... 80 57.46 69 55.16 45 34.67 Dry....................................... 80 68.77 61 49.21 54 43.65 --- ------ --- ------ --- ------ Total................................ 556 451.27 464 355.43 653 509.05 Outside North America Gas....................................... - - 3 2.85 4 3.80 Oil....................................... 1 .30 3 2.85 - - Dry....................................... - - 1 .95 - - --- ------ --- ------ --- ------ Total................................ 1 .30 7 6.65 4 3.80 --- ------ --- ------ --- ------ Total Development............................ 557 451.57 471 362.08 657 512.85 --- ------ --- ------ --- ------ Exploratory Wells Completed North America Gas....................................... 14 10.36 5 4.13 22 17.70 Oil....................................... 1 .78 8 3.61 4 3.07 Dry....................................... 26 19.00 21 13.28 37 30.67 --- ------ --- ------ --- ------ Total................................ 41 30.14 34 21.02 63 51.44 Outside North America Gas....................................... - - 6 4.90 - - Oil....................................... - - - - - - Dry....................................... 1 .50 - - - - --- ------ --- ------ --- ------ Total................................ 1 .50 6 4.90 - - --- ------ --- ------ --- ------ Total Exploratory............................ 42 30.64 40 25.92 63 51.44 --- ------ --- ------ --- ------ Total................................ 599 482.21 511 388.00 720 564.29 Wells in Progress at end of period............. 87 61.08 52 32.71 45 28.79 --- ------ --- ------ --- ------ Total................................ 686 543.29 563 420.71 765 593.08 === ====== === ====== === ====== Wells Acquired Gas....................................... 350 148.20* 277 101.70* 41 40.90* Oil....................................... 5 .65 5 .46 60 38.99* --- ------ --- ------ --- ------ Total................................ 355 148.85 282 102.16 101 79.89 === ====== === ====== === ====== </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. 17
20 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 1996. 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. The First and Second Quarter 1994 sales prices and cash dividends per share have been restated to reflect a two-for-one stock split on May 31, 1994. <TABLE> <CAPTION> PRICE RANGE ---------------- CASH HIGH LOW DIVIDENDS ------ ------ --------- <S> <C> <C> <C> 1994 First Quarter......................................... $23.75 $19.31 $.03 Second Quarter........................................ 24.63 20.88 .03 Third Quarter......................................... 23.75 18.50 .03 Fourth Quarter........................................ 22.75 17.38 .03 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 </TABLE> As of March 1, 1997, there were approximately 280 record holders of the Company's common stock, including individual participants in security position listings. There are an estimated 15,500 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. 18
21 ITEM 6. SELECTED FINANCIAL DATA <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, ------------------------------------------------------------------ 1996 1995 1994 1993 1992 ---------- ---------- ---------- ---------- ---------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) <S> <C> <C> <C> <C> <C> STATEMENT OF INCOME DATA: Net operating revenues....... $ 730,648 $ 648,702 $ 625,823 $ 581,020 $ 459,026 Operating expenses Lease and well............. 76,618 69,463 60,384 59,344 49,406 Exploration................ 55,009 42,044 41,811 36,921 33,278 Dry hole................... 13,193 12,911 17,197 18,355 10,764 Impairment of unproved oil and gas properties...... 21,226 23,715 24,936 20,467 15,136 Depreciation, depletion and amortization............ 251,278 216,047 242,182 249,704 179,839 General and administrative.......... 56,405 56,626 51,418 45,274 36,648 Taxes other than income.... 48,089 32,587 28,254 35,396 28,346 ---------- ---------- ---------- ---------- ---------- Total.............. 521,818 453,393 466,182 465,461 353,417 ---------- ---------- ---------- ---------- ---------- Operating income............. 208,830 195,309 159,641 115,559 105,609 Other income(expense), net ........................... (5,007) 669 2,783 6,635 (3,476) Interest expense (net of interest capitalized)...... 12,861 11,924 8,489 9,921 22,289 ---------- ---------- ---------- ---------- ---------- Income before income taxes... 190,962 184,054 153,935 112,273 79,844 Income tax provision (benefit)(1)............... 50,954(2) 41,936(3) 5,937(4) (25,752)(5) (17,736) ---------- ---------- ---------- ---------- ---------- Net income................... $ 140,008 $ 142,118 $ 147,998 $ 138,025 $ 97,580 ========== ========== ========== ========== ========== Earnings per share of common stock(6)................... $ .88 $ .89 $ .93 $ .86 $ .63 ========== ========== ========== ========== ========== Average number of common shares(6).................. 159,853 159,917 159,845 159,966 154,533 ========== ========== ========== ========== ========== </TABLE> <TABLE> <CAPTION> AT DECEMBER 31, ------------------------------------------------------------------ 1996 1995 1994 1993 1992 ---------- ---------- ---------- ---------- ---------- (IN THOUSANDS) <S> <C> <C> <C> <C> <C> BALANCE SHEET DATA: Oil and gas properties - net........... $2,099,589 $1,881,545 $1,684,811 $1,546,045 $1,468,011 Total assets................. 2,458,353 2,147,258 1,861,867 1,811,162 1,731,012 Long-term debt Affiliate.................. - 141,520 25,000 - -(7) Other...................... 466,089 147,559 165,337 153,000 150,000(7) Deferred revenue............. 56,383 205,453 184,183 227,528 301,395(7) Shareholders' equity......... 1,265,090 1,163,659 1,043,419 933,073 826,986(7) </TABLE> - --------------- (1) Includes benefits of approximately $16 million, $22 million, $36 million, $65 million, and $43 million in 1996, 1995, 1994, 1993, and 1992, respectively, relating to tight gas sand federal income tax credits. (2) 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. (3) Includes a benefit of approximately $14 million associated with the successful resolution on audit of federal income taxes for certain prior years. (4) 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 19
22 from the reduction of the Company's deferred federal income tax liability resulting from a reevaluation of deferred tax requirements. (5) 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%. (6) 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. (7) In August 1992, the Company completed the sale of an additional 8.2 million shares of common stock resulting in aggregate net proceeds to the Company of approximately $112 million used primarily to repay long-term debt. In September 1992, the Company completed the sale of a volumetric production payment, resulting in net proceeds of approximately $327 million used to repay long-term debt and for other general corporate purposes. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following review of operations for each of the three years in the period ended December 31, 1996 should be read in conjunction with the consolidated financial statements of the Company and notes thereto beginning with page F-1. RESULTS OF OPERATIONS Net Operating Revenues. Wellhead volume and price statistics for the specified years were as follows: <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, -------------------------- 1996 1995 1994 ------ ------ ------ <S> <C> <C> <C> Natural Gas Volumes (MMcf per day) North America(1)....................................... 706 636 686 Trinidad............................................... 124 107 63 ------ ------ ------ Total.......................................... 830 743 749 ====== ====== ====== Average Natural Gas Prices ($/Mcf) North America(2)....................................... $ 1.92 $ 1.34 $ 1.68 Trinidad............................................... 1.00 .97 .93 Composite...................................... 1.78 1.29 1.62 Crude Oil/Condensate Volumes (MBbl per day) North America.......................................... 11.6 11.5 10.0 Trinidad............................................... 5.2 5.1 2.5 India.................................................. 2.8 2.5 .1 ------ ------ ------ Total.......................................... 19.6 19.1 12.6 ====== ====== ====== Average Crude Oil/Condensate Prices ($/Bbl) North America.......................................... $21.08 $17.09 $15.65 Trinidad............................................... 19.76 16.07 15.50 India.................................................. 20.17 16.81 15.70 Composite...................................... 20.60 16.78 15.62 </TABLE> - --------------- (1) Includes 48 MMcf per day in 1996, 1995 and 1994 delivered under the terms of volumetric production payment agreement effective October 1, 1992, as amended. (2) Includes an average equivalent wellhead value of $1.17 per Mcf in 1996, $.80 per Mcf in 1995, and $1.27 per Mcf in 1994 for the volumes detailed in note (1), net of transportation costs. 1996 compared to 1995. During 1996, net operating revenues increased $82 million to $731 million as compared to 1995. 20
23 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. Gain 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. 1995 compared to 1994. During 1995, net operating revenues increased $23 million to $649 million as compared to 1994. Average wellhead natural gas prices for 1995 were down approximately 20% from 1994 reducing net operating revenues by approximately $89 million. In addition, a decrease of 1% in wellhead natural gas volumes from 1994 reduced net operating revenues by approximately $4 million. The Company voluntarily curtailed its United States wellhead natural gas delivered volumes by an average of approximately 105 MMcf per day during 1995 compared to approximately 70 MMcf per day during 1994 due to significantly lower United States wellhead natural gas prices. In addition, the impact of reduced drilling for U.S. natural gas deliverability and the sales of oil and gas reserves and related assets (net of purchases of similar assets) resulted in a reduction of approximately 20 MMcf per day in U.S. delivered volumes for 1995 as compared to 1994. The Company refocused its 1995 drilling activity away from natural gas deliverability and toward natural gas reserve enhancement and crude oil exploitation in the United States in response to the significant decline in United States wellhead natural gas prices, in the latter part of 1994 and early 1995, resulting in the drilling of 189 fewer net natural gas wells and 24 more net oil wells during 1995 as compared to 1994. Wellhead crude oil and condensate average prices increased 7% adding approximately $8 million to net operating revenues compared to 1994. Crude oil and condensate wellhead volumes increased 52% adding approximately $37 million to net operating revenues compared to a year ago primarily reflecting new production on stream offshore India and higher volumes offshore Trinidad and in North America. Gains on sales of reserves and related assets during 1995 increased $9 million to $63 million when compared to 1994. Other marketing activities associated with sales and purchases of natural gas, natural gas price swap transactions, other commodity price hedging of natural gas and crude oil and condensate prices utilizing NYMEX-related commodity market transactions and volumetric production payment-related margins added approximately $105 million to net operating revenues during 1995, an increase of approximately $55 million from 1994. This increase primarily resulted from a gain of $65 million on natural gas commodity price hedging activities utilizing NYMEX-related commodity market transactions in 1995 compared to an $11 million gain during 1994. The average associated costs of natural gas marketing, price swap and production exchange transactions, including, where appropriate, average wellhead value, transportation costs and exchange differentials, decreased $.55 per Mcf. The average price received for these transactions decreased $.50 per 21
24 Mcf. Related other natural gas marketing volumes decreased 19%. The reduction in other natural gas marketing volumes and prices relates primarily to the exchange of the fuel contracts noted below, lower wellhead market prices and decreased other marketing activities. The reduction in other natural gas marketing volumes, partially offset by the $.05 per Mcf margin increase, resulted in a decrease in net operating revenues of approximately $2 million compared to 1994. The Company realized an $11 million revenue increase in 1995 related to certain natural gas commodity price swap transactions with an Enron Corp. affiliated company that were designated for trading purposes in late 1994. This revenue increase was partially offset by a revenue reduction of approximately $3 million related to call option transactions and a revenue reduction of $6 million 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 such transactions were designated to hedge. (See "Capital Resources and Liquidity - Hedging Transactions.") In March 1995, the Company exchanged existing fuel supply and purchase contracts and related price swap agreements associated with a Texas City cogeneration plant for certain natural gas price swap agreements of equivalent value issued by an Enron Corp. affiliated company. As a result of these transactions, the Company realized a $13 million increase in net operating revenues in 1995 over the amount realized from the exchanged fuel supply and purchase contracts in 1994 (See "Relationship Between the Company and Enron Corp. - Contractual Agreements".) Operating Expenses 1996 as 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. Depreciation depletion and amortization ("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 thousand cubic feet equivalent ("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. 1995 as compared to 1994. During 1995, operating expenses of $453 million were $13 million lower than the $466 million incurred in 1994. Lease and well expenses increased approximately $9 million to $69 million primarily due to expanded international operations including the initiation of operations in India in late December 1994 and certain nonrecurring costs incurred related to those operations during 1995. DD&A expense decreased $26 million to $216 million reflecting a decrease in the average DD&A rate from $.80 per Mcfe in 1994 to $.68 per Mcfe in 1995. The DD&A rate decrease is primarily attributable to an overall decrease of $.09 per Mcfe in certain North America DD&A rates and an increase in the proportion of production from international operations with lower average DD&A rates than incurred in North America operations. General and administrative expenses increased approximately $5 million to $57 million primarily due to expanded international activities. Taxes other than income were $4 million higher in 1995 compared to 1994 primarily due to higher production related taxes associated with new production in India in 1995. 22
25 The Company reduced its total per unit operating costs for lease and well expense, DD&A, general and administrative expense, interest expense, and taxes other than income by $.07 per Mcfe, averaging $1.22 per Mcfe during 1995 compared to $1.29 per Mcfe in 1994. This decrease is primarily attributable to the reduction in the average DD&A rate as noted above partially offset by slight increases in per unit lease and well, general and administrative expenses, and taxes other than income which increase reflects primarily lower volumes associated with the curtailment of natural gas volumes in the U.S. due to the reduction in wellhead natural gas prices. Other Income (Expense). The 1996 $5 million net expense is primarily comprised of miscellaneous financial reserves partially offset by interest income. Interest Expense. The increase in net interest expense of $1 million from 1995 to 1996 and of $3 million from 1994 to 1995 primarily reflects a higher level of debt outstanding in each subsequent period. (See Note 3 to Consolidated Financial Statements). Income Taxes. 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 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. Income tax provision increased $36 million for 1995 as compared to 1994 primarily resulting from higher income before income taxes, higher foreign income taxed at rates in excess of the U.S. rate and lower benefits associated with tight gas sand federal income tax credits utilized in 1995 as compared to 1994 partially offset by a $14 million benefit associated with the successful resolution on audit of federal income taxes for certain prior years. CAPITAL RESOURCES AND LIQUIDITY Cash Flow. The primary sources of cash for the Company during the three-year period ended December 31, 1996 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 miscellaneous 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 $543 million in 1996, $525 million in 1995 and $514 million in 1994. 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. Net operating cash flows of $335 million for 1995 decreased approximately $47 million as compared to 1994 primarily reflecting higher accounts receivable arising from international activities, and the settlement in December 1995 of January 1996 NYMEX-related natural gas commodity positions. 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 23
26 Note 4 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. Exploration and Development Expenditures. The table below sets out components of actual exploration and development expenditures for the years ended December 31, 1996, 1995 and 1994, along with those budgeted for the year 1997. <TABLE> <CAPTION> ACTUAL -------------------- BUDGETED EXPENDITURE CATEGORY 1996 1995 1994 1997 -------------------- ---- ---- ---- -------- (IN MILLIONS) <S> <C> <C> <C> <C> Capital Drilling and Facilities..................... $408 $303 $342 Leasehold Acquisitions............................ 45 22 52 Producing Property Acquisitions................... 69 127 34 Capitalized Interest and Other.................... 18 12 14 ---- ---- ---- Total..................................... 540 464 442 Exploration Expenses................................ 68 55 59 ---- ---- ---- Total............................................... $608 $519 $501 $600 ==== ==== ==== ==== </TABLE> 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. Exploration and development expenditures increased $18 million in 1995 as compared to 1994. Differences in components reflect a significant increase in producing property acquisitions to complement existing United States producing areas. One such property acquisition was for non-cash consideration of $19 million of redeemable preferred stock of a subsidiary of the Company. (See Note 9 to Consolidated Financial Statements). (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 1997 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. In 1996, prices for approximately 65% of the natural gas delivered volumes were hedged using NYMEX-related commodity price swaps compared to 35% in 1995. The Company's 1996 NYMEX-related natural gas and crude oil commodity price swaps closed with "other marketing revenue" reductions of $18 million pretax and $13 million pretax, respectively. 24
27 During December 1996, the Company closed a significant portion of its NYMEX-related natural gas commodity price swaps for 1997. The removal of these hedges resulted in a deferred "other marketing revenue" reduction of $56.1 million pretax to be realized during 1997. At December 31, 1996, there were open commodity price swaps for 1997 covering approximately 10 TBtu of natural gas at a weighted average price of $2.26 per MMBtu, predominantly in the first quarter and approximately 2 million barrels of crude oil at a weighted average price of $19.01 per barrel. Financing. The Company's long-term debt-to-total-capital ratio was 27% and 20% as of December 31, 1996 and 1995, 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. There was no balance outstanding under either agreement at December 31, 1996 and $142 million outstanding at December 31, 1995 under the terms of the borrowing agreement. During 1996, total long-term debt increased $177 million to $466 million as a result of borrowings related to increased domestic drilling activities, international facilities construction and certain producing property acquisitions. (See Note 3 to the Consolidated Financial Statements). The estimated fair value of the Company's long-term debt at December 31, 1996 and 1995 was $464 million and $294 million, respectively, based upon quoted market prices and, where such prices were not available, upon interest rates currently available to the Company at year end. (See Note 12 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 and colder weather experienced in the latter part of 1995 and 1996 than in prior years. 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, 1996, based on the portion of the Company's anticipated natural gas volumes 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 $13 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 $4 million for each $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, the opportunities available to the Company in conjunction with the late 1994 signing of agreements in India, the winning in 1996 of a concession in Venezuela, and the award of the modified U(a) block offshore Trinidad, the Company anticipates expending an increasing 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 $600 million for 1997. 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 continuation of expenditures 25
28 in other areas outside of North America in the near term is expected to be primarily for the evaluation of conventional oil and gas exploitation opportunities in China. Other prospects in various locations including coalbed methane recovery projects will also attract the expenditure of some funds. 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 1996, 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 benefit, which was approximately $16 million in 1996 and is estimated to be approximately $11 million for 1997, 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. The level of exploration and development expenditures may vary in 1997 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 1997 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 and Venezuela, such commitments are not anticipated to be material when considered in relation to the total financial capacity of the Company. 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. 26
29 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. 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 December 3, 1996 reporting the sale on November 18, 1996 of $150 million principal amount of 6.70% Notes due November 15, 2006 pursuant to an underwritten public offering. 27
30 INDEX TO FINANCIAL STATEMENTS ENRON OIL & GAS COMPANY <TABLE> <CAPTION> PAGE ---- <S> <C> Consolidated Financial Statements: Management's Responsibility for Financial Reporting....... F-2 Reports of Independent Public Accountants................. F-3 Consolidated Statements of Income for Each of the Three Years in the Period Ended December 31, 1996...................................... F-4 Consolidated Balance Sheets - December 31, 1996 and 1995................................................... F-5 Consolidated Statements of Shareholders' Equity for Each of the Three Years in the Period Ended December 31, 1996................................................... F-6 Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 1996...... F-7 Notes to Consolidated Financial Statements................ F-8 Supplemental Information to Consolidated Financial Statements................................................ F-23 Financial Statement Schedule: Schedule II - Valuation and Qualifying Accounts and Reserves............................................... S-1 </TABLE> Other financial statement schedules have been omitted because they are inapplicable or the information required therein is included elsewhere in the consolidated financial statements or notes thereto. F-1
31 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. Arthur Andersen LLP was also engaged to examine and report on management's assertion about the effectiveness of the system of internal controls of Enron Oil & Gas Company and its subsidiaries. The reports of Arthur Andersen LLP appear on the following page. 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 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, 1996. <TABLE> <S> <C> <C> BEN B. BOYD WALTER C. WILSON FORREST E. HOGLUND Chairman of the Vice President and Senior Vice President and Board and Chief Executive Controller Chief Financial Officer Officer </TABLE> Houston, Texas February 17, 1997 F-2
32 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To Enron Oil & Gas Company: We have examined management's assertion that the system of internal control of Enron Oil & Gas Company and its subsidiaries for the year ended December 31, 1996 was adequate to provide reasonable assurance as to the reliability of financial statements and the protection of assets against unauthorized acquisition, use or disposition, included in the accompanying report on Management's Responsibility for Financial Reporting. Our examination was made in accordance with standards established by the American Institute of Certified Public Accountants and, accordingly, included obtaining an understanding of the system of internal control, testing and evaluating the design and operating effectiveness of the system of internal control and such other procedures as we considered necessary in the circumstances. We believe that our examination provides a reasonable basis for our opinion. Because of inherent limitations in any system of internal control, errors or irregularities may occur and not be detected. Also, projections of any evaluation of the system of internal control to future periods are subject to the risk that the system of internal control may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, management's assertion that the system of internal control of Enron Oil & Gas Company and its subsidiaries for the year ended December 31, 1996 was adequate to provide reasonable assurance as to the reliability of financial statements and the protection of assets against unauthorized acquisition, use or disposition is fairly stated in all material respects, based upon current standards of control criteria. Houston, Texas ARTHUR ANDERSEN LLP February 17, 1997 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, 1996 and 1995, and the related consolidated statements of income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 1996. 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, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, 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 17, 1997 F-3
33 ENRON OIL & GAS COMPANY CONSOLIDATED STATEMENTS OF INCOME (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, -------------------------------- 1996 1995 1994 -------- -------- -------- <S> <C> <C> <C> NET OPERATING REVENUES Natural Gas Associated Companies.................................. $164,745 $229,997 $267,997 Trade................................................. 393,129 222,118 221,896 Crude Oil, Condensate and Natural Gas Liquids Associated Companies.................................. 37,539 58,233 46,782 Trade................................................. 108,365 66,145 29,556 Gains on Sales of Reserves and Related Assets............ 20,358 62,821 54,014 Other.................................................... 6,512 9,388 5,578 -------- -------- -------- Total............................................ 730,648 648,702 625,823 OPERATING EXPENSES Lease and Well........................................... 76,618 69,463 60,384 Exploration.............................................. 55,009 42,044 41,811 Dry Hole................................................. 13,193 12,911 17,197 Impairment of Unproved Oil and Gas Properties............ 21,226 23,715 24,936 Depreciation, Depletion and Amortization................. 251,278 216,047 242,182 General and Administrative............................... 56,405 56,626 51,418 Taxes Other Than Income.................................. 48,089 32,587 28,254 -------- -------- -------- Total............................................ 521,818 453,393 466,182 -------- -------- -------- OPERATING INCOME........................................... 208,830 195,309 159,641 OTHER INCOME (EXPENSE), NET................................ (5,007) 669 2,783 -------- -------- -------- INCOME BEFORE INTEREST EXPENSE AND TAXES................... 203,823 195,978 162,424 INTEREST EXPENSE Incurred Affiliate............................................. 1,614 1,360 629 Other................................................. 20,383 17,054 13,984 Capitalized.............................................. (9,136) (6,490) (6,124) -------- -------- -------- Net Interest Expense.................................. 12,861 11,924 8,489 -------- -------- -------- INCOME BEFORE INCOME TAXES................................. 190,962 184,054 153,935 INCOME TAX PROVISION....................................... 50,954 41,936 5,937 -------- -------- -------- NET INCOME................................................. $140,008 $142,118 $147,998 ======== ======== ======== EARNINGS PER SHARE OF COMMON STOCK......................... $ .88 $ .89 $ .93 ======== ======== ======== AVERAGE NUMBER OF COMMON SHARES............................ 159,853 159,917 159,845 ======== ======== ======== </TABLE> The accompanying notes are an integral part of these consolidated financial statements. F-4
34 ENRON OIL & GAS COMPANY CONSOLIDATED BALANCE SHEETS (IN THOUSANDS) <TABLE> <CAPTION> AT DECEMBER 31, -------------------------- 1996 1995 ----------- ----------- <S> <C> <C> ASSETS CURRENT ASSETS Cash and Cash Equivalents................................. $ 7,644 $ 23,039 Accounts Receivable Associated Companies................................... 82,059 60,777 Trade.................................................. 195,239 107,737 Inventories............................................... 20,746 11,697 Other..................................................... 20,222 14,582 ----------- ----------- Total............................................. 325,910 217,832 OIL AND GAS PROPERTIES (Successful Efforts Method).......... 3,753,199 3,380,924 Less: Accumulated Depreciation, Depletion and Amortization........................................... (1,653,610) (1,499,379) ----------- ----------- Net Oil and Gas Properties........................ 2,099,589 1,881,545 OTHER ASSETS................................................ 32,854 47,881 ----------- ----------- TOTAL ASSETS................................................ $ 2,458,353 $ 2,147,258 =========== =========== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES >Accounts Payable Associated Companies................................... $ 77,522 $ 12,902 Trade.................................................. 200,069 120,756 Accrued Taxes Payable..................................... 18,554 19,595 Dividends Payable......................................... 4,818 4,795 Other..................................................... 16,397 11,249 ----------- ----------- Total............................................. 317,360 169,297 LONG-TERM DEBT Affiliate................................................. - 141,520 Other..................................................... 466,089 147,559 OTHER LIABILITIES........................................... 44,483 11,629 DEFERRED INCOME TAXES....................................... 308,948 308,141 DEFERRED REVENUE............................................ 56,383 205,453 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................................ 388,212 399,379 Unearned Compensation..................................... (5,727) - Cumulative Foreign Currency Translation Adjustment........ (10,179) (10,747) Retained Earnings......................................... 697,564 576,740 Common Stock Held in Treasury, 242,882 shares at December 31, 1996 and 150,045 shares at December 31, 1995....... (6,380) (3,313) ----------- ----------- Total Shareholders' Equity........................ 1,265,090 1,163,659 ----------- ----------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY.................. $ 2,458,353 $ 2,147,258 =========== =========== </TABLE> The accompanying notes are an integral part of these consolidated financial statements. F-5
35 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, 1993...... $200,800 $417,531 $ - $ (6,855) $324,995 $ (3,398) $ 933,073 Net Income...................... - - - - 147,998 - 147,998 Two-for-One Stock Split......... 800 (800) - - - - - Dividends Paid/Declared, $.12 Per Share..................... - - - - (19,183) - (19,183) Translation Adjustment.......... - - - (8,443) - - (8,443) Treasury Stock Purchased/ Tendered...................... - - - - - (35,960) (35,960) Treasury Stock Issued Under Stock Option Plans............ - (13,243) - - - 39,177 25,934 -------- -------- ------- -------- -------- -------- ---------- 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/ Tendered...................... - - - - - (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 ======== ======== ======= ======== ======== ======== ========== </TABLE> The accompanying notes are an integral part of these consolidated financial statements. F-6
36 ENRON OIL & GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS) <TABLE> <CAPTION> YEAR ENDED DECEMBER 31, --------------------------------- 1996 1995 1994 --------- --------- --------- <S> <C> <C> <C> CASH FLOWS FROM OPERATING ACTIVITIES Reconciliation of Net Income to Net Operating Cash Inflows: Net Income.............................................. $ 140,008 $ 142,118 $ 147,998 Items Not Requiring (Providing) Cash Depreciation, Depletion and Amortization........................... 251,278 216,047 242,182 Impairment of Unproved Oil and Gas Properties........ 21,226 23,715 24,936 Deferred Income Taxes................................ 2,276 45,173 1,788 Other, Net........................................... 7,830 2,910 (2,735) Exploration Expenses.................................... 55,009 42,044 41,811 Dry Hole Expenses....................................... 13,193 12,911 17,197 Gains On Sales of Reserves and Related Assets........... (20,358) (62,821) (54,014) Other, Net.............................................. 8,871 720 4,490 Changes in Components of Working Capital and Other Liabilities Accounts Receivable................................ (120,370) (17,525) (883) Inventories........................................ (9,049) 4,034 (2,163) Accounts Payable................................... 87,495 2,514 (25,648) Accrued Taxes Payable.............................. (1,041) 1,964 277 Other Liabilities.................................. 3,752 1,544 1,086 Other, Net......................................... 270 (18,791) (1,463) Amortization of Deferred Revenue........................ (43,463) (43,344) (43,345) Changes in Components of Working Capital Associated with Investing and Financing Activities................... (31,817) (17,858) 31,038 --------- --------- --------- NET OPERATING CASH INFLOWS................................ 365,110 335,355 382,552 INVESTING CASH FLOWS Additions to Oil and Gas Properties..................... (539,330) (445,047) (442,078) Exploration Expenses.................................... (55,009) (42,044) (41,811) Dry Hole Expenses....................................... (13,193) (12,911) (17,197) Proceeds from Sales of Reserves and Related Assets (Note 9)................................................... 63,951 102,006 90,515 Changes in Components of Working Capital Associated with Investing Activities................................. 37,402 18,391 (32,120) Other, Net.............................................. (5,381) (11,689) (8,758) --------- --------- --------- NET INVESTING CASH OUTFLOWS............................... (511,560) (391,294) (451,449) FINANCING CASH FLOWS Long-Term Debt Affiliate............................................ (141,520) 116,520 25,000 Other................................................ 320,580 (16,100) (25,300) Dividends Paid.......................................... (19,161) (19,193) (19,178) Treasury Stock Purchased................................ (43,507) (17,855) (14,139) Proceeds from Sales of Treasury Stock................... 22,188 10,329 4,113 Other, Net.............................................. (7,525) (533) 1,082 --------- --------- --------- NET FINANCING CASH INFLOWS (OUTFLOWS)..................... 131,055 73,168 (28,422) --------- --------- --------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS.......... (15,395) 17,229 (97,319) CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR............ 23,039 5,810 103,129 --------- --------- --------- CASH AND CASH EQUIVALENTS AT END OF YEAR.................. $ 7,644 $ 23,039 $ 5,810 ========= ========= ========= </TABLE> The accompanying notes are an integral part of these consolidated financial statements. F-7
37 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"), 53% of the outstanding common stock of which is owned by Enron Corp., 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. 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
38 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 Interest and Price Risk Management. The Company engages in price and interest rate risk management activities for primarily non-trading purposes. Such activities consist of transactions to hedge commodity prices associated with the sale of natural gas and crude oil in order to mitigate the risk of market price fluctuations and interest rate swap agreements to effectively convert portions of floating rate debt to a fixed rate basis, thereby reducing the impact of interest rate changes on future income. Changes in the market value of commodity price and interest rate swap transactions entered into as hedges are deferred so that the gain or loss is recognized in the period in which the revenues or expenses associated with the hedged transactions are applicable. In certain situations, the Company has designated portions of and may in the future designate certain commodity price swap transactions or portions thereof as for trading purposes. These transactions are accounted for using the mark-to-market method of accounting. Under this method, unrealized gains or losses resulting from the impact of price movements are recognized as net gains or losses in net operating revenues in the consolidated statements of income. 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 with significant cash outlays. Interest costs capitalized during each of the three years in the period ended December 31, 1996 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 from 80% to 61% 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 previously in effect between the Company and Enron Corp. was terminated. In addition effective December 14, 1995, the Company and its subsidiaries and Enron Corp. entered into a new tax agreement pursuant to which, among other things, Enron Corp. has agreed (in exchange for the payment of $13.0 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%. The Company does not believe that the cessation of consolidated tax reporting with Enron Corp., the termination of the tax allocation agreement concurrent with deconsolidation and/or the signing of the new tax agreement with Enron Corp. has 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 tax allocation agreement in effect prior to December 14, 1995. The Company accounts for income taxes under the provisions of SFAS No. 109 - "Accounting for Income Taxes". SFAS No. 109 requires the asset and liability approach for accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases (See Note 7 "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. F-9
39 Earnings Per Share. Earnings per share is computed on the basis of the average number of common shares outstanding during the periods. 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> 1996 1995 1994 -------- -------- -------- <S> <C> <C> <C> Wellhead Natural Gas Revenues Associated Companies(1)(2)....................... $216,676 $173,864 $279,339 Trade............................................ 323,642 174,732 162,553 -------- -------- -------- Total.................................... $540,318 $348,596 $441,892 ======== ======== ======== Other Natural Gas Marketing Activities Gross Revenues from: Associated Companies.......................... $ 92,471 $ 78,985 $159,726 Trade(3)...................................... 142,149 102,904 121,965 -------- -------- -------- Total.................................... 234,620 181,889 281,691 Associated Costs from: Associated Companies(1)(5).................... 143,871 90,121(4) 181,756(4) Trade......................................... 72,633.. 56,221.. 62,513 -------- -------- -------- Total.................................... 216,504 146,342 244,269 -------- -------- -------- Net...................................... 18,116 35,547 37,422 Commodity Price Transaction Gain (Loss) Trading....................................... (13,222)(6) 2,688(7) - Non-Trading(8)................................ 12,662 65,284 10,579 -------- -------- -------- Total.................................... (560) 67,972 10,579 -------- -------- -------- Total.................................... $ 17,556 $103,519 $ 48,001 ======== ======== ======== </TABLE> Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues are comprised of the following: <TABLE> <CAPTION> 1996 1995 1994 -------- -------- -------- <S> <C> <C> <C> Wellhead Crude Oil, Condensate and Natural Gas Liquids Revenues Associated Companies.......................... $ 50,668 $ 56,681 $ 44,979 Trade......................................... 108,365 66,145 29,556 -------- -------- -------- Total.................................... $159,033 $122,826 $ 74,535 ======== ======== ======== Other Crude Oil and Condensate Marketing Activities Commodity Price Hedging Gain (Loss)(8)........... $(13,129) $ 1,552 $ 1,803 ======== ======== ======== </TABLE> - --------------- (1) Wellhead Natural Gas Revenues in 1996, 1995 and 1994 include $119,009, $80,369 and $126,783, 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 $20,656, $14,022 and $22,434 in 1996, 1995 and 1994, 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 $43,463, $43,344 and $43,345 in 1996, 1995 and 1994, respectively, associated with the amortization of deferred revenues under the terms of a volumetric production payment agreement effective October 1, 1992, as amended. F-10
40 (4) Includes the effect of a price swap agreement with a third party which in effect fixed the price of certain purchases through February 1995. (5) Includes $37,483, $27,549 and $33,779 in 1996, 1995 and 1994, 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. (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 12 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 12 "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 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 $33 million and $60 million at December 31, 1996 and 1995, respectively, and are presented in the accompanying balance sheet as Accounts Receivable - Associated Companies for the $20 million and $25 million current portion, respectively, and as Other Assets for the $13 million and $35 million noncurrent portion, respectively. The corresponding total future revenue of approximately $33 million and $63 million, respectively, is classified as Deferred Revenue. (See Note 12 "Price and Interest Rate Risk Management"). F-11
41 3. LONG-TERM DEBT Long-Term Debt at December 31 consisted of the following: <TABLE> <CAPTION> 1996 1995 -------- -------- <S> <C> <C> Commercial Paper and/or Uncommitted Credit Facilities....... $ 65,700 $ - 6.70% Notes due 2006........................................ 150,000 - 9.10% Notes due 1998........................................ 40,000 70,000 Bank Debt due 1999.......................................... 30,000 - Subsidiary Bank Debt due 1998-1999.......................... 71,000 71,000 Subsidiary Bank Debt due 2001............................... 105,000 - Capitalized Lease/Other..................................... 4,389 6,559 -------- -------- 466,089 147,559 Affiliate................................................... - 141,520 -------- -------- Total............................................. $466,089 $289,079 ======== ======== </TABLE> In June 1996, the Company cancelled an existing revolving credit agreement and replaced it with a new revolving credit agreement entered into with a group of banks. The new agreement provides for aggregate borrowings of up to $200 million and matures on June 28, 2001. Advances under the agreement bear interest, at the option of the Company, based on a base rate, an adjusted CD rate or a Eurodollar rate. At December 31, 1996, there were no advances outstanding under the agreement. The Company has uncommitted credit facilities, of which approximately $66 million was outstanding as of December 31, 1996. Advances under these credit facilities bear interest based on market rates. The proceeds of the Company's credit facilities are used to fund current transactions and are classified as long-term debt based on the Company's intent and ability to replace such amounts with other long-term debt. The 6.70% Notes were issued through a public offering in November 1996 and are due November 15, 2006. These notes have an effective interest rate of 6.83%. The 9.10% Notes have scheduled principal repayments of $20 million due February 15, 1997 and 1998. The $20 million repayment due on February 15, 1997 is classified as long-term based on the Company's intent and ability to replace such amount upon maturity with other long-term debt. The Bank Debt due 1999 bears interest at a variable rate based on the London Interbank Offered Rate. The Subsidiary Bank Debt due 1998-1999 represents multiple advances bearing interest at a fixed rate or at a variable rate based on the London Interbank Bid Rate with $31 million due in 1998 and $40 million due in 1999. The Subsidiary Bank Debt due 2001 bears interest at a variable rate based on the London Interbank Offered Rate. 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 bank debt is guaranteed by the Company. Shelf Registration. The Company may sell from time to time up to an aggregate of $313 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. There were no borrowings from or investments with Enron Corp. under these agreements at December 31, 1996. Borrowings of $142 million were outstanding at F-12
42 December 31, 1995, 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. Fair Value Of Long-Term Debt. At December 31, 1996 and 1995, the Company had $466 million and $289 million, respectively, of long-term debt which had fair values of approximately $464 million and $294 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. 4. 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, 1996 and 1995 there were approximately 41 trillion British thermal units ("TBtu") and 60 TBtu, respectively, 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, 1996 was as follows: <TABLE> <S> <C> 1997............................................... $43,344 1998............................................... 43,344 1999............................................... 10,688 ------- Total.................................... $97,376 ======= </TABLE> 5. SHAREHOLDERS' EQUITY On May 3, 1994, the shareholders of the Company approved and the Board of Directors subsequently 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. At such time, an amendment to the Restated Certificate of Incorporation of the Company to increase the total number of authorized shares of the common stock of the Company from 80 million to 160 million shares and to change the par value of common stock from no par to $.01 par per share was filed with the Secretary of State of Delaware. All share and per share amounts in the financial statements and supplemental financial information have been restated to consider the effect of the two-for-one stock split. In March 1995, a subsidiary of the Company issued to an unrelated third party 19,000 shares of the subsidiary's non-voting redeemable preferred stock, with a liquidation/redemption value of $1,000 per share and dividends payable semi-annually at an annual rate of $70.00 per share, in exchange for certain oil and gas properties. In November 1995, the Company exchanged 633,333 shares of Enron Corp. common stock which had been acquired in 1994 and 1995 for the redeemable preferred stock. 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. (See Note 8 "Commitments and Contingencies - Stock Option Plans"). In December 1996, the Board F-13
43 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 shares limit mentioned above applies to shares held in treasury and unexpired put options outstanding. At December 31, 1996 and 1995, 242,882 shares and 150,045 shares, respectively, were held in treasury under this authorization, and there were no put options outstanding. In February 1997, the Board of Directors of the Company authorized the additional purchase of up to an aggregate maximum of 5 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. 6. TRANSACTIONS WITH ENRON CORP. AND RELATED PARTIES 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 8 "Commitments and Contingencies - Employee Benefit Plans"), totaled $17.0 million, $16.4 million and $13.4 million for the years ended December 31, 1996, 1995 and 1994, 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, 1994, the Company entered into an agreement with Enron Corp. with an initial term of five years through December 1998, 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 $7.5 million, $7.0 million and $6.7 million for 1996, 1995 and 1994, 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, but such increase will not exceed 7.5% per year. Management believes the indirect allocated charges for the numerous types of support services provided by the corporate staff are reasonable. Approximately $7.5 million, $6.8 million and $6.6 million were charged to the Company for indirect general and administrative expenses for the years ended December 31, 1996, 1995 and 1994, respectively. Financing. See Note 3 "Long-Term Debt - Financing Arrangements with Enron Corp." for a discussion of financing arrangements with Enron Corp. F-14
44 7. INCOME TAXES The principal components of the Company's net deferred income tax liability at December 31, 1996 and 1995 were as follows: <TABLE> <CAPTION> 1996 1995 -------- -------- <S> <C> <C> <C> Deferred Income Tax Assets Non-Producing Leasehold Costs.................... $ 9,832 $ 8,469 Seismic Costs Capitalized for Tax................ 7,037 5,316 Alternative Minimum Tax Credit Carryforward...... 7,516 - Other............................................ 5,013 1,460 -------- -------- Total Deferred Income Tax Assets......... 29,398 15,245 Deferred Income Tax Liabilities Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization.................... 278,094 274,219 Capitalized Interest............................. 7,401 6,265 Volumetric Production Payment Book Revenue Over Income for Tax................................ 51,499 40,591 Other............................................ 1,352 2,311 -------- -------- Total Deferred Income Tax Liabilities.... 338,346 323,386 -------- -------- Net Deferred Income Tax Liability........ $308,948 $308,141 ======== ======== </TABLE> The components of income before income taxes were as follows: <TABLE> <CAPTION> 1996 1995 1994 -------- -------- -------- <S> <C> <C> <C> United States...................................... $146,335 $157,174 $125,510 Foreign............................................ 44,627 26,880 28,425 -------- -------- -------- Total.................................... $190,962 $184,054 $153,935 ======== ======== ======== </TABLE> Total income tax provision (benefit) was as follows: <TABLE> <CAPTION> 1996 1995 1994 -------- -------- -------- <S> <C> <C> <C> Current: Federal.......................................... $ 21,064 $ (6,983) $ 113 State............................................ (916) 130 2,745 Foreign.......................................... 28,530 3,616 1,291 -------- -------- -------- Total.................................... 48,678 (3,237) 4,149 Deferred: Federal.......................................... 13,620 24,733 3,818 State............................................ (1,826) 855 (14,414) Foreign.......................................... (9,518) 19,585 12,384 -------- -------- -------- Total.................................... 2,276 45,173 1,788 -------- -------- -------- Income Tax Provision............................... $ 50,954 $ 41,936 $ 5,937 ======== ======== ======== </TABLE> F-15
45 The differences between taxes computed at the U.S. federal statutory tax rate and the Company's effective rate were as follows: <TABLE> <CAPTION> 1996 1995 1994 ----- ------ ------ <S> <C> <C> <C> Statutory Federal Income Tax Rate......................... 35.00% 35.00% 35.00% State Income Tax, Net of Federal Benefit.................. (0.76) 0.35 (4.93) Income Tax Related to Foreign Operations.................. 6.16 7.21 3.44 Tight Gas Sand Federal Income Tax Credits................. (8.22) (12.19) (23.71) Revision of Prior Years' Tax Estimates.................... (4.46) (6.52) (3.25) Amended Return Recoveries................................. - (1.09) (2.62) Other..................................................... (1.04) 0.02 (0.07) ----- ------ ------ Effective Income Tax Rate....................... 26.68% 22.78% 3.86% ===== ====== ====== </TABLE> The Company's foreign subsidiaries' undistributed earnings of approximately $119 million at December 31, 1996 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 an alternative minimum tax ("AMT") credit carryforward of $7.5 million which can be used to offset regular income taxes payable in future years. The AMT credit carryforward has an indefinite carryforward period. 8. 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, 1996, 1995 and 1994, the Company was charged $5.0 million, $6.6 million and $5.1 million, respectively, for all such benefits, including pension expense totaling $1.0 million, $0.8 million and $0.3 million, respectively, by Enron Corp. As of September 30, 1996, 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 $5 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 7.5%, 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 generally 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 of the grants and as defined in the individual grant agreements. Options granted under the Plans have not exceeded a maximum term of 10 years. In January 1996, 301,500 shares of common stock of the Company with a market value of $23.50 per share were granted 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 F-16
46 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 1996 was approximately $1 million. 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 for the Plans for the years ended December 31 (shares in thousands): <TABLE> <CAPTION> 1996 1995 1994 ---------------- ---------------- ---------------- AVERAGE AVERAGE AVERAGE GRANT GRANT GRANT SHARES PRICE SHARES PRICE SHARES PRICE ------ ------- ------ ------- ------ ------- <S> <C> <C> <C> <C> <C> <C> Outstanding at January 1........... 8,019 $18.61 7,215 $18.15 4,125 $11.49 Granted.......................... 2,941 24.53 1,650 18.57 5,128 20.23 Exercised........................ (1,989) 17.95 (622) 13.01 (1,968) 9.46 Forfeited........................ (175) 20.28 (224) 19.27 (70) 19.95 ------ ----- ------ Outstanding at December 31......... 8,796 20.70 8,019 18.61 7,215 18.15 ====== ===== ====== Shares Exercisable at December 31............................... 4,402 19.13 4,716 18.23 1,822 15.57 ====== ===== ====== Shares Available for Future Grant............................ 3,741 3,792 3,218 ====== ===== ====== Average Fair Value of Shares Granted During Year.............. $ 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 1996 and 1995, respectively: (1) dividend yield of 0.5% and 0.5%, (2) expected volatility of 31% and 31%, (3) risk-free interest rate of 5.8% and 7.2%, and (4) expected life of 5.5 years and 4.1 years. The following table summarizes certain information for the shares outstanding at December 31, 1996 (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 ------------ ------ --------- -------- ------- --------- <S> <C> <C> <C> <C> <C> $ 9.00 to $13.00........................ 529 4 years $ 9.89 529 $ 9.89 13.00 to 18.00........................ 1,195 6 17.83 689 17.80 18.00 to 23.00........................ 4,040 6 20.10 2,560 20.30 23.00 to 29.00........................ 3,032 9 24.53 624 23.61 ----- ----- 9.00 to 29.00........................ 8,796 7 20.70 4,402 19.13 ===== ===== </TABLE> F-17
47 The Company's pro forma net income and earnings per share of common stock for 1996 and 1995, had compensation costs been recorded in accordance with SFAS No. 123, are presented below (in millions except per share data): <TABLE> <CAPTION> 1996 1995 --------------------- --------------------- AS AS REPORTED PRO FORMA REPORTED PRO FORMA -------- --------- -------- --------- <S> <C> <C> <C> <C> Net Income................................ $140.0 $135.5 $142.1 $139.0 Earnings per Share of Common Stock........ $ .88 $ .85 $ .89 $ .87 </TABLE> The effects of applying SFAS No. 123 in this pro forma disclosure are not indicative of future amounts. SFAS No. 123 does not apply to awards prior to 1995, and additional awards in future years are anticipated. 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 greatly 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 1996, 1995 and 1994, the Company purchased or was tendered 2,383,727, 762,799 and 1,817,093 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, 1996, 1995 and 1994. The difference between the cost of the treasury shares and the exercise price of the options, net of federal income tax benefit of $6.1 million, $2.2 million and $7.2 million for the years 1996, 1995 and 1994, respectively, is reflected as an adjustment to Additional Paid In Capital. In October 1993, as amended in September 1994 and December 1996, the Company commenced a stock repurchase program 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. At December 31, 1996 and 1995, 242,882 and 150,045 shares, respectively, were held in treasury under this authorization. (See Note 5 "Shareholders' Equity"). Letters Of Credit. At December 31, 1996 and 1995, the Company had letters of credit outstanding totaling approximately $213 million and $32 million, respectively. Contingencies. There are various 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. 9. CASH FLOW INFORMATION Gains on sales of certain oil and gas reserves and related assets in the amount of $20.4 million, $62.8 million and $54.0 million for the years ended December 31, 1996, 1995 and 1994, 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 $8.5 million, $24.4 million and $19.8 million for the years ended December 31, 1996, 1995 and 1994, 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. F-18
48 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 (See Note 5 "Shareholders' Equity"). 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. Cash paid for interest and income taxes was as follows for the years ended December 31: <TABLE> <CAPTION> 1996 1995 1994 ---------- ---------- ---------- <S> <C> <C> <C> Interest (net of amount capitalized)........... $ 14,237 $ 11,307 $ 10,436 Income taxes................................... 42,014 10,140 1,352 </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%. 10. 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> 1996 1995 1994 ---------- ---------- ---------- <S> <C> <C> <C> Gross Operating Revenues United States................................ $ 660,804 $ 582,993 $ 656,546 Foreign...................................... 167,340 131,682 86,763 ---------- ---------- ---------- Total(1)............................. $ 828,144 $ 714,675 $ 743,309 ========== ========== ========== Operating Income United States................................ $ 160,109 $ 162,652 $ 138,001 Foreign...................................... 48,721 32,657 21,640 ---------- ---------- ---------- Total................................ $ 208,830 $ 195,309 $ 159,641 ========== ========== ========== Identifiable Assets United States................................ $1,882,900 $1,693,293 $1,505,926 Foreign...................................... 575,453 453,965 355,941 ---------- ---------- ---------- Total................................ $2,458,353 $2,147,258 $1,861,867 ========== ========== ========== </TABLE> - --------------- (1) Not deducted are natural gas associated costs of $97,496, $65,973 and $117,486 in 1996, 1995 and 1994, respectively. 11. OTHER INCOME (EXPENSE), NET Other income (expense), net consisted of the following for the years ended December 31: <TABLE> <CAPTION> 1996 1995 1994 ---------- ---------- ---------- <S> <C> <C> <C> Interest Income(1)............................. $ 2,264 $ 556 $ 4,990 Financial Reserve Accruals..................... (6,897) 379 (3,143) Other, Net..................................... (374) (266) 936 ---------- ---------- ---------- Total................................ $ (5,007) $ 669 $ 2,783 ========== ========== ========== </TABLE> - --------------- (1) Includes $403, $59 and $4,716 from related parties. F-19
49 12. 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. 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 for each of the years 1997 and 1998 which was exercisable at one time prior to December 31, 1996. The 1996 price swaps were 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 $12 million revenue reduction in 1996 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. There were no trading gains or losses in 1994. The following table summarizes the estimated fair value of financial instruments held for trading purposes at year-end and the average during the year: <TABLE> <CAPTION> 1996(1) 1995(1) -------------------- ------------------- FAIR AVERAGE FAIR AVERAGE VALUE FAIR VALUE VALUE FAIR VALUE ------ ---------- ----- ---------- (IN MILLIONS) (IN MILLIONS) <S> <C> <C> <C> <C> Options Written................................ $(12.8) $(8.3) $(1.8) $(.3) NYMEX-related Natural Gas Price Swaps.......... .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, 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, 1996, the composite fair value of the agreements was not significant based upon termination values obtained from third parties. At December 31, 1995, there were no interest rate swap agreements or foreign currency contracts outstanding. F-20
50 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 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 hedged natural gas production. This loss of correlation resulted in the recognition of a $6 million revenue reduction in 1995. 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 million barrels ("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. At December 31, 1995, the Company had outstanding positions covering notional volumes of approximately 169 TBtu of natural gas for 1996 and 11 TBtu of natural gas for each of the years 1997 through 2005 and approximately 3.6 MMBbl, 2.8 MMBbl, 2.8 MMBbl, 2.2 MMBbl, and .9 MMBbl of crude oil and condensate for the years 1996 through 2000, respectively. The fair value of the positions was $16 million at December 31, 1995. The following table summarizes the estimated fair value of financial instruments and related transactions for non-trading activities at December 31, 1996 and 1995: <TABLE> <CAPTION> 1996 1995 ------------------------ ------------------------ CARRYING ESTIMATED CARRYING ESTIMATED AMOUNT FAIR VALUE(1) AMOUNT FAIR VALUE(1) -------- ------------- -------- ------------- (IN MILLIONS) (IN MILLIONS) <S> <C> <C> <C> <C> Long-Term Debt(2)........................... $466.1 $ 464.5 $289.1 $294.0 Swap Agreements............................. 32.8 31.0 62.8 58.8 NYMEX-Related Commodity Market Positions.... (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 3 "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. F-21
51 13. CONCENTRATION OF CREDIT RISK Substantially all of the Company's accounts receivable at December 31, 1996 and 1995 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-22
52 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, 1996, 1995 and 1994 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, 1996, 1995 and 1994 covering producing areas containing 64%, 60% and 59%, 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. F-23
53 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 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, 1996 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, 1996, 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 TOTAL ------------- ------ -------- ------ ------- <S> <C> <C> <C> <C> <C> Natural Gas (Bcf)(1) Net proved reserves at December 31, 1993.... 1,313.2 271.0 100.5 - 1,684.7 Revisions of previous estimates.......... (17.1) (6.5) 15.0 - (8.6) Purchases in place....................... 18.8 9.2 - 29.3 57.3 Extensions, discoveries and other additions.............................. 233.8 50.2 113.9 - 397.9 Sales in place........................... (29.3) (1.0) - - (30.3) Production............................... (212.0) (26.3) (23.2) - (261.5) ------- ------ ------ ------ ------- Net proved reserves at December 31, 1994.... 1,307.4 296.6 206.2 29.3 1,839.5 Additional disclosures: Volumes attributable to volumetric production payment..................... 70.9 - - - 70.9 ------- ------ ------ ------ ------- Net proved reserves at December 31, 1994, including volumes attributable to volumetric production payment............ 1,378.3 296.6 206.2 29.3 1,910.4 ======= ====== ====== ====== ======= 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 ======= ====== ====== ====== ======= </TABLE> (Table continued on following page) F-24
54 <TABLE> <CAPTION> UNITED STATES CANADA TRINIDAD INDIA TOTAL ------------- ------ -------- ------ ------- <S> <C> <C> <C> <C> <C> 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 ======= ====== ====== ====== ======= Liquids (MBbl)(3)(4) Net proved reserves at December 31, 1993.... 13,172 5,471 2,218 - 20,861 Revisions of previous estimates.......... 2,179 (177) 455 - 2,457 Purchases in place....................... 358 - - 7,617 7,975 Extensions, discoveries and other additions.............................. 5,332 2,848 2,687 - 10,867 Sales in place........................... (257) - - - (257) Production............................... (2,997) (905) (931) (32) (4,865) ------- ------ ------ ------ ------- 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 ======= ====== ====== ====== ======= Bcf Equivalent (Bcfe) Net proved reserves at December 31, 1993.... 1,392.2(5) 303.8 113.8 - 1,809.8 Revisions of previous estimates.......... (4.0) (7.6) 17.8 - 6.2 Purchases in place....................... 21.0 9.2 - 75.0 105.2 Extensions, discoveries and other additions.............................. 265.8 67.3 130.0 - 463.1 Sales in place........................... (30.9) (1.0) - - (31.9) Production............................... (229.9) (31.8) (28.8) (0.2) (290.7) ------- ------ ------ ------ ------- 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) ------- ------ ------ ------ ------- </TABLE> (Table continued on following page) F-25
55 <TABLE> <CAPTION> UNITED STATES CANADA TRINIDAD INDIA TOTAL ------------- ------ -------- ------ ------- <S> <C> <C> <C> <C> <C> 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) ------- ------ ------ ------ ------- Net proved reserves at December 31, 1996.... 2,920.1(2) 365.3 419.2 264.3 3,968.9 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............ 2,957.6 365.3 419.2 264.3 4,006.4 ======= ====== ====== ====== ======= Net proved developed reserves at Natural Gas (Bcf) December 31, 1993................... 1,079.8 250.6 71.4 - 1,401.8 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 Liquids (MBbl)(4) December 31, 1993................... 11,165 5,409 1,591 - 18,165 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 Bcf Equivalents December 31, 1993................... 1,146.8 283.1 80.9 - 1,510.8 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 Net proved developed reserves, including amounts attributable to volumetric production payment at Natural Gas (Bcf) December 31, 1993................... 1,167.3 250.6 71.4 - 1,489.3 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 </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 87 Bcfe, 71 Bcfe and 54 Bcfe at December 31, 1993, 1994 and 1995, respectively, related to a volumetric production payment. F-26
56 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, 1996 and 1995: <TABLE> <CAPTION> 1996 1995 ----------- ----------- <S> <C> <C> Proved Properties......................................... $ 3,593,230 $ 3,253,593 Unproved Properties....................................... 159,969 127,331 ----------- ----------- Total........................................... 3,753,199 3,380,924 Accumulated depreciation, depletion and amortization...... (1,653,610) (1,499,379) ----------- ----------- Net capitalized costs..................................... $ 2,099,589 $ 1,881,545 =========== =========== </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 in progress, and depreciation of support equipment used in exploration activities. Development costs include additions to production facilities and equipment, additions to development wells in progress and related facilities, 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> 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 4,092 16,490 91,613 Development Costs.................... 283,985 25,705 6,654 78,754 6,969 402,067 -------- ------- ------- ------- ------- -------- 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 ======== ======= ======= ======= ======= ======== 1994 Acquisition Costs of Properties Unproved........................... $ 45,776 $ 6,618 $ - $ - $ (17) $ 52,377 Proved............................. 17,367 4,523 - 12,300 - 34,190 -------- ------- ------- ------- ------- -------- Total...................... 63,143 11,141 - 12,300 (17) 86,567 Exploration Costs.................... 70,669 8,210 850 2,302 11,242 93,273 Development Costs.................... 223,241 35,896 60,778 767 564 321,246 -------- ------- ------- ------- ------- -------- Total...................... $357,053 $55,247 $61,628 $15,369 $11,789 $501,086 ======== ======= ======= ======= ======= ======== </TABLE> F-27
57 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> 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 ======== ======= ======= ======= ======== ======== 1994 Operating Revenues Associated Companies................................. $315,866 $ 8,452 $ - $ - $ - $324,318 Trade................................................ 115,375 42,017 35,908 509 - 193,809 Gains on Sales of Reserves and Related Assets........ 54,026 (12) - - - 54,014 -------- ------- ------- ------- -------- -------- Total.......................................... 485,267 50,457 35,908 509 - 572,141 Exploration Expenses, including Dry Hole............... 42,242 4,503 836 2,302 9,125 59,008 Production Costs....................................... 68,998 12,776 5,083 26 - 86,883 Impairment of Unproved Oil and Gas Properties.......... 23,862 1,074 - - - 24,936 Depreciation, Depletion and Amortization............... 218,433 16,572 6,572 - 281 241,858 -------- ------- ------- ------- -------- -------- Income (Loss) before Income Taxes...................... 131,732 15,532 23,417 (1,819) (9,406) 159,456 Income Tax Provision (Benefit)......................... (8,617) 6,175 12,804 (910) (2,873) 6,579 -------- ------- ------- ------- -------- -------- Results of Operations.................................. $140,349 $ 9,357 $10,613 $ (909) $ (6,533) $152,877 ======== ======= ======= ======= ======== ======== </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, 1996. 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-28
58 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-29
59 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 TOTAL ------ ------ -------- ----- ----- <S> <C> <C> <C> <C> <C> 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(1)............ 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)............ 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 =========== ========= ========= ========= =========== 1994 Future cash inflows(1).................................. $ 2,315,215 $ 487,050 $ 317,758 $ 168,370 $ 3,288,393 Future production costs................................. (606,932) (196,275) (87,479) (105,840) (996,526) Future development costs................................ (135,768) (9,596) (1,781) (4,500) (151,645) ----------- --------- --------- --------- ----------- Future net cash flows before income taxes............... 1,572,515 281,179 228,498 58,030 2,140,222 Future income taxes..................................... (208,163) (57,220) (102,171) (22,482) (390,036) ----------- --------- --------- --------- ----------- Future net cash flows................................... 1,364,352 223,959 126,327 35,548 1,750,186 Discount to present value at 10% annual rate............ (401,547) (67,018) (22,897) (14,730) (506,192) ----------- --------- --------- --------- ----------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves(1)............ 962,805 156,941 103,430 20,818 1,243,994 Additional disclosures: Amounts attributable to volumetric production payment............................................. 60,269 - - - 60,269 ----------- --------- --------- --------- ----------- Total discounted future net revenues, including amounts attributable to volumetric production payment............................................. $ 1,023,074 $ 156,941 $ 103,430 $ 20,818 $ 1,304,263 =========== ========= ========= ========= =========== </TABLE> - --------------- (1) Based on year end market prices determined at the point of delivery from the producing unit. F-30
60 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, 1996. <TABLE> <CAPTION> UNITED STATES CANADA TRINIDAD INDIA TOTAL ------ ------ -------- ----- ----- <S> <C> <C> <C> <C> <C> December 31, 1993....................................... $1,262,368(1) $159,771 $ 49,579 $ - $1,471,718 Sales and transfers of oil and gas produced, net of production costs............................. (339,809) (37,693) (30,825) (483) (408,810) Net changes in prices and production costs............ (506,273) (65,287) 11,002 - (560,558) Extensions, discoveries, additions and improved recovery net of related costs................................ 225,366 51,006 96,515 - 372,887 Development costs incurred............................ 69,900 6,700 7,582 - 84,182 Revisions of estimated development costs.............. 6,792 5,931 - - 12,723 Revisions of previous quantity estimates.............. (2,909) (3,407) 14,077 - 7,761 Accretion of discount................................. 145,119 19,762 7,448 - 172,329 Net change in income taxes............................ 167,983 19,966 (45,789) (7,752) 134,408 Purchases of reserves in place........................ 16,651 3,404 - 29,053 49,108 Sales of reserves in place............................ (27,980) (461) - - (28,441) Changes in timing and other........................... (54,403) (2,751) (6,159) - (63,313) ---------- -------- --------- -------- ---------- 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(2) 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 relating to proved oil and gas reserves, including amounts attributable to volumetric production payment, at December 31, 1996................................... $2,566,850 $225,758 $ 156,838 $194,185 $3,143,631 ========== ======== ========= ======== ========== </TABLE> - --------------- (1) Excludes $105,323, $60,269 and $35,957 at December 31, 1993, 1994 and 1995, respectively, related to a volumetric production payment. (2) Includes approximately $77,453 and $344,319, discounted before income taxes, in 1995 and 1996, respectively, related to the reserves in the Big Piney deep Paleozoic formations. F-31
61 UNAUDITED QUARTERLY FINANCIAL INFORMATION <TABLE> <CAPTION> QUARTER ENDED ----------------------------------------- MARCH 31 JUNE 30 SEPT. 30 DEC. 31 -------- -------- -------- -------- <S> <C> <C> <C> <C> 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.......... $ .16 $ .30 $ .20 $ .22 ======== ======== ======== ======== Average Number of Common Shares............. 159,934 159,910 159,850 159,719 ======== ======== ======== ======== 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.......... $ .19 $ .30 $ .21 $ .20 ======== ======== ======== ======== Average Number of Common Shares............. 159,972 159,965 159,916 159,817 ======== ======== ======== ======== 1994 Net Operating Revenues...................... $158,208 $155,449 $160,683 $151,483 ======== ======== ======== ======== Operating Income............................ $ 38,938 $ 39,081 $ 52,020 $ 29,602 ======== ======== ======== ======== Income before Income Taxes.................. $ 39,088 $ 36,581 $ 50,497 $ 27,769 Income Tax Provision (Benefit).............. 8,830 2,369 9,529 (14,791) -------- -------- -------- -------- Net Income.................................. $ 30,258 $ 34,212 $ 40,968 $ 42,560 ======== ======== ======== ======== Earnings per Share of Common Stock.......... $ .19 $ .21 $ .26 $ .27 ======== ======== ======== ======== Average Number of Common Shares............. 159,840 159,859 159,777 159,902 ======== ======== ======== ======== </TABLE> F-32
62 SCHEDULE II ENRON OIL & GAS COMPANY SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994 (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> 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 $ - ====== ====== ====== ====== 1994 Reserves deducted from assets to which they apply - Revaluation of Accounts Receivable........ $1,020 $ 2 $ - $1,022 ====== ====== ====== ====== Litigation Reserve(a)....................... $2,000 $3,143 $3,143 $2,000 ====== ====== ====== ====== </TABLE> - --------------- (a) Included in Other Liabilities in the consolidated balance sheets. (b) Includes reversal of prior year provision in excess of requirement. S-1
63 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> <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). 3.2* - 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. 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). 10.1 - Services Agreement, dated as of January 1, 1994, between Enron Oil & Gas Company and Enron Corp. (Exhibit 10.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.2 - Stock Restriction and Registration Agreement dated as of August 23, 1989 (Exhibit 10.2 to Form S-1). 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
64 <TABLE> <S> <C> 10.9(a) - Employment Agreement between Enron Oil & Gas Company and Forrest Hoglund, dated as of September 1, 1987, as amended (Exhibit 10.19 to Form S-1), and Second and Third Amendments to Employment Agreement dated June 30, 1989 and February 14, 1992, respectively (Exhibit 10.10 to Form S-1 Registration Statement No. 33-50462, filed August 5, 1992). 10.9(b) - 4th Amendment to Employment Agreement dated December 14, 1994, among Enron Corp., Enron Oil & Gas Company and Forrest Hoglund (Exhibit 10.9(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1994). 10.14(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. 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, Registration No. 33-50462, filed on 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). </TABLE> E-2
65 <TABLE> <S> <C> 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). 10.34 - 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). 10.35 - 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). </TABLE> E-3
66 <TABLE> <S> <C> 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). 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). </TABLE> E-4
67 <TABLE> <S> <C> 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). 21* - List of subsidiaries. 23.1* - Consent of DeGolyer and MacNaughton. 23.2* - Opinion of DeGolyer and MacNaughton dated January 17, 1997. 23.3* - Consent of Arthur Andersen LLP. 24* - Powers of Attorney. 27* - Financial Data Schedule. </TABLE> E-5
68 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 7th day of March, 1997. 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 7th day of March, 1997. <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) KENNETH L. LAY* Director - ----------------------------------------------------- (Kenneth L. Lay) EDWARD RANDALL, III* Director - ----------------------------------------------------- (Edward Randall, III) EDMUND P. SEGNER, III* Director - ----------------------------------------------------- (Edmund P. Segner, III) *By /s/ ANGUS H. DAVIS ------------------------------------------------- (Angus H. Davis) (Attorney-in-fact for persons indicated) </TABLE>
69 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). 3.2* - 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. 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). 10.1 - Services Agreement, dated as of January 1, 1994, between Enron Oil & Gas Company and Enron Corp. (Exhibit 10.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 10.2 - Stock Restriction and Registration Agreement dated as of August 23, 1989 (Exhibit 10.2 to Form S-1). 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). 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). </TABLE>
70 <TABLE> <CAPTION> EXHIBIT NUMBER DESCRIPTION ------- ----------- <C> <S> 10.14(b)* - First Amendment to Enron Oil & Gas Company 1993 Nonemployee Directors' Stock Option Plan. 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, Registration No. 33-50462, filed on 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). 10.34 - 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). 10.35 - 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). </TABLE>
71 <TABLE> <CAPTION> EXHIBIT NUMBER DESCRIPTION ------- ----------- <C> <S> 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). 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). </TABLE>
72 <TABLE> <CAPTION> EXHIBIT NUMBER DESCRIPTION ------- ----------- <C> <S> 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). 21* - List of subsidiaries. 23.1* - Consent of DeGolyer and MacNaughton. 23.2* - Opinion of DeGolyer and MacNaughton dated January 17, 1997. 23.3* - Consent of Arthur Andersen LLP. 24* - Powers of Attorney. 27* - Financial Data Schedule. </TABLE>