-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, SoChwOEp6YpVnZogrDu0xcgh1rJb2v3DBHzpOiLgjtGTuFn9Q3B8JNzjcWD4BO/V R+eMJSs4wZapRpxyHbvfuQ== 0000950129-99-003552.txt : 19990812 0000950129-99-003552.hdr.sgml : 19990812 ACCESSION NUMBER: 0000950129-99-003552 CONFORMED SUBMISSION TYPE: 424B1 PUBLIC DOCUMENT COUNT: 1 FILED AS OF DATE: 19990811 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ENRON OIL & GAS CO CENTRAL INDEX KEY: 0000821189 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 470684736 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B1 SEC ACT: SEC FILE NUMBER: 333-83533 FILM NUMBER: 99683416 BUSINESS ADDRESS: STREET 1: 1400 SMITH ST CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 7138535482 424B1 1 ENRON OIL & GAS COMPANY 1 FILED PURSUANT TO RULE 424(B)(1) REGISTRATION NO. 333-83533 333-84913 31,000,000 Shares [ENRON LOGO] ENRON OIL & GAS COMPANY Common Stock ---------------------- Enron Oil & Gas Company is offering 27,000,000 shares of its common stock. Enron Corp. is offering an additional 4,000,000 shares. EOG will not receive any of the proceeds from the sale of the shares being sold by Enron Corp. The common stock is listed on the New York Stock Exchange under the symbol "EOG". The last reported sale price of the common stock on August 10, 1999 was $22.375 per share. Enron Corp. is offering concurrently, in a separate public offering with a separate prospectus 10,000,000 (11,500,000 if the underwriters in that offering fully exercise their over-allotment option) Exchangeable Notes, which are mandatorily exchangeable into shares of EOG common stock currently owned by Enron Corp. This offering of EOG common stock and the concurrent offering of Exchangeable Notes by Enron Corp. are not conditioned on each other. Consider carefully the risk factors beginning on page 10 of this prospectus. ---------------------- NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY OTHER REGULATORY BODY HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. ----------------------
Per Share Total --------- ------------ Initial price to public..................................... $22.25 $689,750,000 Underwriting discount....................................... $ 0.83 $ 25,730,000 Proceeds, before expenses, to EOG........................... $21.42 $578,340,000 Proceeds, before expenses, to Enron Corp.................... $21.42 $ 85,680,000
To the extent that the underwriters sell more than 31,000,000 shares of common stock, the underwriters have the option to purchase up to an additional 4,500,000 shares from Enron Corp. at the initial price to public less the underwriting discount. ---------------------- The underwriters expect to deliver the shares against payment in New York, New York on August 16, 1999. GOLDMAN, SACHS & CO. BANC OF AMERICA SECURITIES LLC DAIN RAUSCHER WESSELS A DIVISION OF DAIN RAUSCHER INCORPORATED LEHMAN BROTHERS MERRILL LYNCH & CO. PAINEWEBBER INCORPORATED SALOMON SMITH BARNEY WARBURG DILLON READ LLC ---------------------- Prospectus dated August 10, 1999. 2 ENRON OIL & GAS COMPANY [MAP OF DISTRIBUTION OF PRODUCTION] - ------------------------- *NATURAL GAS EQUIVALENT DAILY PRODUCTION AT DECEMBER 31, 1998. OIL AND GAS TERMS When describing commodities produced and sold: gas = natural gas oil = crude oil liquids = crude oil, condensate and natural gas liquids When describing natural gas: Mcf = thousand cubic feet MMcf = million cubic feet Bcf = billion cubic feet MMBtu = million British Thermal Units When describing oil: Bbl = barrel MBbl = thousand barrels MMBbl = million barrels When comparing oil to natural gas: 1 Bbl of oil = 6 Mcf of natural gas equivalent Mcfe = thousand cubic feet equivalent MMcfe = million cubic feet equivalent Bcfe = billion cubic feet equivalent
2 3 PROSPECTUS SUMMARY This summary highlights selected information we have included or incorporated by reference in this prospectus. However, it does not contain all information that may be important to you. More detailed information about this offering, our business and our financial and operating data is contained elsewhere in this prospectus. We encourage you to read this prospectus in its entirety before making an investment decision. In this prospectus, we refer to Enron Oil & Gas Company and its subsidiaries as "we", "us", "our" or "EOG" unless the context clearly indicates otherwise. ABOUT EOG EOG is one of the largest independent exploration and production companies in the United States. We explore for and produce natural gas and oil in almost every major producing basin in the United States and Canada and internationally in India and Trinidad and, to a lesser extent, selected other areas. SHARE EXCHANGE WITH ENRON CORP. On July 20, 1999, EOG and Enron Corp. announced an agreement to exchange 62,270,000 shares of our common stock out of 82,270,000 shares currently owned by Enron Corp. for all the stock of our subsidiary, EOGI-India, Inc. Prior to the Share Exchange, we will make an indirect $600,000,000 cash capital contribution, plus certain intercompany receivables, to EOGI-India, Inc. At the time of completion of this transaction, this subsidiary will own, through subsidiaries, all of our assets and operations in India and China. We expect this transaction to be tax-free to Enron Corp. and us. We refer to this transaction elsewhere in this prospectus as the Share Exchange. Some time after the Share Exchange, we expect to change our corporate name to "EOG Resources, Inc." and we will make appropriate changes to our subsidiaries' names. See "Relationship with Enron Corp." The completion of the Share Exchange is subject to specific conditions and we currently expect the Share Exchange to close on August 16, 1999. We will use borrowed funds for the cash capital contribution in connection with the Share Exchange, and we will repay a portion of those borrowed funds with the net proceeds of this offering which will close after the Share Exchange, also on August 16, 1999. Upon completion of the Share Exchange, all of the directors of EOG who are affiliated with Enron Corp. will resign from our Board of Directors. For the complete terms of our agreement with Enron Corp., please refer to the Share Exchange Agreement between Enron Corp. and us filed as an exhibit to the registration statement that includes this prospectus. EOG RESOURCES, INC. As EOG Resources, Inc., our reserves and production will be predominantly comprised of natural gas, and will be primarily located in North America. On a pro forma basis, 77% of our total reserves will be located in, and 85% of our production will be derived from, the United States or Canada, with natural gas comprising 87% of total production, on a natural gas equivalent basis as of or for the year ended December 31, 1998. After giving effect to the Share Exchange, at December 31, 1998, our estimated total net proved reserves included: - 4,294 Bcf of gas, including: - 1,180 Bcf of proved undeveloped methane reserves in the Big Piney deep Paleozoic formations in Wyoming and - 61 MMBbl of liquids. 3 4 After giving effect to the Share Exchange, at December 31, 1998, - 66% of our reserves (on a natural gas equivalent basis) was located in the United States - 11% in Canada and - 23% in Trinidad. After giving effect to the Share Exchange, for the year ended December 31, 1998 our delivered volumes (on a natural gas equivalent basis) were - 282 Bcfe in the United States, - 46 Bcfe in Canada and - 57 Bcfe in Trinidad. BUSINESS STRATEGY Our strategy is to maximize the return on invested capital by achieving operating and finding costs that are among the lowest in the industry. We are focused on growing our domestic natural gas reserves and production by concentrating our efforts in known North American reserve basins. We focus on selected international opportunities where we can successfully apply our core competencies in the exploitation of reserves. Our strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost effective basis. Our North American operations are organized into seven largely autonomous business units, each focusing on a basin or basins, utilizing personnel who have developed experience and expertise unique to the geology of the region, thereby leveraging our knowledge and cost structure into enhanced returns on invested capital. We focus our drilling activity toward natural gas deliverability in addition to natural gas reserve enhancement and to a lesser extent crude oil exploitation. We also focus on the cost-effective utilization of advances in technology associated with gathering, processing and interpretation of 3-D seismic data, developing reservoir simulation models and drilling operations through the use of new and/or improved drill bits, mud motors, mud additives, formation logging techniques and reservoir fracturing methods. These advanced technologies are used, as appropriate, throughout the company to reduce the risks associated with all aspects of oil and gas reserve exploration, exploitation and development. We implement our strategy by emphasizing the drilling of internally generated prospects in order to find and develop low cost reserves. We also make selected tactical acquisitions that give us additional economies of scale or land positions with significant additional prospects. Achieving and maintaining the lowest possible operating cost structure are also important goals in the implementation of our strategy. Consistent with our desire to optimize the use of our assets, we also sell selected oil and gas properties that for various reasons may no longer fit into future operating plans or which we believe do not have sufficient future growth potential. We do this when we believe the economic value to be obtained by selling the properties and reserves in the ground is greater than what we would obtain by holding the properties and producing the reserves over time. As a result, we typically receive each year a varying but substantial level of proceeds related to such sales. We use these proceeds for general corporate purposes. 4 5 RECENT DEVELOPMENTS We have executed a series of new credit agreements totaling $1.3 billion, and have simultaneously cancelled our existing credit facilities which totaled $450 million. Of the $1.3 billion credit facilities, $500 million will expire in 364 days, $400 million is structured as a 364-day revolving credit facility with a one-year term subsequent to the revolving period, and $400 million is structured as a five-year revolving credit facility. The $500 million credit facility will be cancelled when we receive the proceeds from this offering. If advances have been made under the $500 million credit facility when this offering is completed, such advances will be repaid and the facility then will be cancelled. These new credit agreements contain financial covenants which may restrict to some extent our ability to incur additional indebtedness. However, we do not believe these covenants to be materially restrictive given current market conditions. On July 21, 1999, two stockholders of EOG filed separate lawsuits purportedly on behalf of EOG against Enron Corp. and EOG's directors, alleging that Enron Corp. and EOG's directors breached their fiduciary duties of good faith and loyalty in approving the Share Exchange. The lawsuits seek to temporarily and permanently enjoin the Share Exchange and seek compensatory damages and costs and expenses, including reasonable attorneys' and experts' fees. EOG, Enron Corp. and the EOG directors believe the lawsuits are without merit and intend to vigorously contest them. As a result of the change to our portfolio of assets subsequent to the Share Exchange, we are currently re-evaluating our overall business. We expect to complete this re-evaluation by the end of third quarter 1999. As a result of this re-evaluation, some of our current projects may no longer be deemed central to our business. In that case, we may incur non-cash charges in connection with the disposition of such projects of up to approximately $75 million, after-tax. THE OFFERING - Shares offered by EOG..........................................27,000,000 - Shares offered by Enron Corp......................................................4,000,000 - Approximate number of shares outstanding after this offering and the Share Exchange...............................................118,625,137* - New York Stock Exchange symbol................................................................EOG - Use of proceeds..........................................We expect to use the net proceeds from this offering of approximately $577.7 million to repay a portion of the indebtedness incurred in connection with the Share Exchange to fund a cash capital contribution to our subsidiaries that conduct our India and China operations. The pending Share Exchange with Enron Corp. is discussed in "Prospectus Summary -- Share Exchange With Enron Corp." We will not receive any proceeds from the sale of shares of our common stock by Enron Corp. or the underwriters' exercise of the over-allotment option. - ------------------------- * Based on an aggregate of 153,895,137 shares of our common stock outstanding as of June 30, 1999. 5 6 CONCURRENT OFFERING Enron Corp. is offering concurrently, in a separate public offering with a separate prospectus 10,000,000 (11,500,000 if the underwriters in that offering fully exercise their over-allotment option) Exchangeable Notes, which are mandatorily exchangeable into shares of our common stock currently owned by Enron Corp. This offering of our common stock and the concurrent offering of Exchangeable Notes by Enron Corp. are not conditioned on each other. The Share Exchange Agreement provides that for a period of six months following the closing of the Share Exchange Enron may not sell any shares of our common stock other than those covered by this prospectus and the Exchangeable Notes. We will not receive any proceeds from the Exchangeable Notes offering. 6 7 SUMMARY OF HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA The following table sets forth our summary selected historical financial and operating data as of and for each of the three years in the period ended December 31, 1998 and the six-month periods ended June 30, 1998 and 1999 and our pro forma financial and operating data as of and for the year ended December 31, 1998 and the six-month period ended June 30, 1999. This information should be read in conjunction with our consolidated financial statements and the related notes incorporated by reference in this prospectus (see "Where You Can Find More Information") and our condensed consolidated pro forma financial statements and the related notes included elsewhere in this prospectus. Financial information for each of the three years in the period ended December 31, 1998 has been derived from audited financial statements. Financial information for the six-month periods ended June 30, 1998 and 1999 has been derived from unaudited financial statements. The interim data reflects all adjustments which, in the opinion of our management, are necessary to present fairly such information for the interim periods. Results of the six-month periods are not necessarily indicative of the results expected for a full year or any other interim period. The unaudited condensed consolidated pro forma information is for informational purposes only, and does not necessarily represent what our actual results of operations would have been had the Share Exchange occurred on the dates indicated under "Unaudited Condensed Consolidated Pro Forma Financial Information".
PRO FORMA PRO FORMA SIX MONTHS ENDED SIX MONTHS YEAR ENDED DECEMBER 31, YEAR ENDED JUNE 30, ENDED ---------------------------------- DECEMBER 31, ---------------------- JUNE 30, 1996 1997 1998 1998 1998 1999 1999 -------- -------- -------- ------------ -------- -------- ----------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) STATEMENT OF INCOME DATA: Net operating revenues........ $730,648 $783,501 $769,188 $696,351 $383,138 $346,149 $305,880 Operating expenses Lease and well............... 76,618 96,064 98,868 87,749 47,766 47,607 40,462 Exploration costs............ 55,009 57,696 65,940 63,408 33,998 27,091 25,444 Dry hole costs............... 13,193 17,303 22,751 22,751 10,162 2,475 2,475 Impairment of unproved oil and gas properties......... 21,226 27,213 32,076 32,076 15,703 15,987 15,987 Depreciation, depletion and amortization............... 251,278 278,179 315,106 305,786 145,032 170,803 164,992 General and administrative... 56,405 54,415 69,010 57,967 31,758 50,019 39,486 Taxes other than income...... 48,089 59,856 51,776 45,161 27,764 26,076 21,774 -------- -------- -------- -------- -------- -------- -------- Total.................. 521,818 590,726 655,527 614,898 312,183 340,058 310,620 -------- -------- -------- -------- -------- -------- -------- Operating income (loss)....... 208,830 192,775 113,661 81,453 70,955 6,091 (4,740) Other income (expense), net... (5,007) (1,588) (4,800) 306 (1,043) 58,290(1) 59,217(1) Interest expense (net of interest capitalized)........ 12,861 27,717 48,579 56,990 19,533 29,041 33,009 -------- -------- -------- -------- -------- -------- -------- Income before income taxes.... 190,962 163,470 60,282 24,769 50,379 35,340 21,468 Income tax provision (benefit)(2)................. 50,954(3) 41,500(4) 4,111(5) (7,944)(5) 10,117(6) 9,636(7)(8) 5,325(7)(8) -------- -------- -------- -------- -------- -------- -------- Net income.................... $140,008 $121,970 $ 56,171 $ 32,713 $ 40,262 $ 25,704 $ 16,143 ======== ======== ======== ======== ======== ======== ======== Net income per share of common stock Basic........................ $ 0.88 $ 0.78 $ 0.36 $ 0.27 $ 0.26 $ 0.17 $ 0.14 ======== ======== ======== ======== ======== ======== ======== Diluted...................... $ 0.87 $ 0.77 $ 0.36 $ 0.27 $ 0.26 $ 0.17 $ 0.13 ======== ======== ======== ======== ======== ======== ======== Average number of common shares Basic........................ 159,853 157,376 154,345 119,075 154,797 153,779 118,509 ======== ======== ======== ======== ======== ======== ======== Diluted...................... 161,525 158,160 155,054 119,784 155,646 154,943 119,673 ======== ======== ======== ======== ======== ======== ========
7 8
PRO FORMA AT DECEMBER 31, AT AT ------------------------------------ JUNE 30, JUNE 30, 1996 1997 1998 1999 1999 ---------- ---------- ---------- ---------- ---------- (IN THOUSANDS) BALANCE SHEET DATA: Oil and gas properties - net........................... $2,099,589 $2,387,207 $2,676,363 $2,666,848 $2,424,696 Total assets........................................... 2,458,353 2,723,355 3,018,095 2,962,046 2,649,103 Long-term debt Trade................................................ 466,089 548,775 942,779 1,073,883 1,123,883 Affiliate............................................ - 192,500 200,000 66,000 66,000 Deferred revenue....................................... 56,383 39,918 4,198 2,099 2,099 Shareholders' equity................................... 1,265,090 1,281,049 1,280,304 1,310,044 1,013,582
PRO FORMA SIX YEAR ENDED PRO FORMA SIX MONTHS MONTHS DECEMBER 31, YEAR ENDED ENDED JUNE 30, ENDED ------------------------ DECEMBER 31, --------------- JUNE 30, 1996 1997 1998 1998 1998 1999 1999 ------ ------ ------ ------------- ------ ------ --------- OPERATING DATA: Wellhead Volumes and Prices Natural Gas Volumes (MMcf per day).............. 830 889 971 915 904 982 908 Average Natural Gas Prices ($/Mcf).............. $ 1.78 $ 2.07 $ 1.78 $ 1.74 $ 1.87 $ 1.67 $ 1.65 Crude/Condensate Volumes (MBbl per day)......... 19.6 19.9 24.7 19.6 22.3 25.1 18.4 Average Crude/Condensate Prices ($/Bbl)......... $20.60 $19.30 $12.66 $12.61 $13.82 $13.04 $13.49
- --------------- (1) Includes a gain of $60 million related to the sale of options held by EOG to purchase 3.2 million shares of Enron Corp. common stock. (2) Includes benefits of approximately $16 million, $12 million, $12 million, $12 million, $4 million, $3 million and $3 million in the year ended December 31, 1996, 1997, 1998 and 1998 (pro forma), and the six-month period ended June 30, 1998, 1999 and 1999 (pro forma), respectively, relating to tight gas sand federal income tax credits. (3) Includes a benefit of $9 million primarily associated with a reassessment of deferred tax requirements and the successful resolution on audit of Canadian income taxes for certain prior years. (4) Includes a benefit of $15 million primarily associated with the refiling of certain Canadian tax returns and the sale of certain international assets and subsidiaries. (5) Includes a benefit of $2 million related to the final audit assessments of India taxes for certain prior years, a benefit of $4 million related to reduced deferred franchise taxes, and $4 million related to Venezuela deferred tax benefits. (6) Includes a benefit of $8 million related to certain international costs and the resolution of certain state and international issues. (7) Federal income taxes accrued in the six-month interim periods are calculated using the estimated annual effective income tax rate. (8) Includes a benefit of $4 million related to anticipated disposition of certain international assets. 8 9 SUMMARY OF HISTORICAL AND PRO FORMA OIL AND GAS RESERVE INFORMATION The following table sets forth summary information with respect to EOG's estimates of its net proved natural gas, crude oil, condensate and natural gas liquids reserves at December 31, 1998. For additional information relating to reserves, see "Business -- Oil and Gas Exploration and Production Properties and Reserves".
NATURAL GAS EQUIVALENTS (BCFE) GAS LIQUIDS ------------------------------- (BCF) (MBBL) DEVELOPED UNDEVELOPED TOTAL ----- --------- --------- ----------- ----- HISTORICAL: Net proved reserves at December 31, 1998: United States........................ 2,854(1) 36,827 1,628 1,446(1) 3,074(1) Canada............................... 464 7,592 432 78 510 Trinidad............................. 976 16,204 312 762 1,074 India................................ 825 42,785 608 473 1,081 Other................................ 110 1,162 - 117 117 ----- ------- ----- ----- ----- Total........................... 5,229 104,570 2,980 2,876 5,856 ===== ======= ===== ===== =====
NATURAL GAS EQUIVALENTS (BCFE) GAS LIQUIDS ------------------------------- (BCF) (MBBL) DEVELOPED UNDEVELOPED TOTAL ------- --------- --------- ----------- ----- PRO FORMA: Net proved reserves at December 31, 1998, as adjusted(2): United States......................... 2,854(1) 36,827 1,628 1,446(1) 3,074(1) Canada................................ 464 7,592 432 78 510 Trinidad.............................. 976 16,204 312 762 1,074 ----- ------- ----- ----- ----- Total............................ 4,294 60,623 2,372 2,286 4,658 ===== ======= ===== ===== =====
- --------------- (1) Includes 1,180 Bcf of methane reserves in the Big Piney deep Paleozoic formations in Wyoming. (2) Adjusted to reflect the effect of the Share Exchange. 9 10 RISK FACTORS In considering whether to purchase shares of our common stock, you should carefully consider the risk factors described below and all the information we have included or incorporated by reference in this prospectus. In addition, please read "Cautionary Statement Regarding Forward-Looking Statements" on page 15 of this prospectus, where we describe uncertainties associated with our business and the forward-looking statements included or incorporated by reference in this prospectus. A SUBSTANTIAL OR EXTENDED DECLINE IN OIL OR GAS PRICES WOULD HAVE A MATERIAL ADVERSE EFFECT ON US. Prices for natural gas and oil fluctuate widely. For example, natural gas and oil prices declined significantly in 1998 and, for an extended period of time, remained substantially below prices obtained in previous years. Since we are primarily a natural gas company, we are more significantly affected by changes in natural gas prices than changes in the prices for crude oil, condensate or natural gas liquids. Among the factors that can cause these price fluctuations are: - the level of consumer demand, - weather conditions, - price and availability of alternative fuels, - domestic drilling activity and - overall economic conditions. During 1995, 1996, 1997 and 1998, the high and low prices for natural gas and oil on the twelve-month forward NYMEX strip were:
GAS OIL ------------- --------------- HIGH LOW HIGH LOW ----- ----- ------ ------ 1995................. $2.09 $1.57 $19.16 $16.58 1996................. 2.73 1.85 23.27 16.90 1997................. 2.79 2.02 23.38 18.29 1998................. 2.72 1.92 18.41 12.17
The average North America wellhead natural gas prices we received increased 43% from 1995 to 1996 and 15% from 1996 to 1997, while the average North America wellhead natural gas prices we realized from 1997 to 1998 decreased by 15%. Wellhead natural gas volumes from the Trinidad SECC Block are sold at prices that are based on a fixed schedule with periodic escalations. No formal contract has been entered into regarding future production of proved reserves from the Trinidad U(a) Block. 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, we are unable to predict what changes may occur in natural gas prices in the future. We sell substantially all of our wellhead crude oil and condensate 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 worldwide energy supplies and the relative competitive relationships of the various energy sources in the view of the consumers, the level of consumer demand and the availability of alternative fuels, we are unable to predict what changes may occur in crude oil and condensate prices in the future. Our cash flow and earnings depend to a great extent on the prevailing prices for natural gas and oil. Prolonged or substantial declines in these commodity prices may adversely affect our liquidity, the amount of cash flow available for capital expenditures and our ability to maintain our credit quality and access to the credit and capital markets. OUR ABILITY TO SELL OUR OIL AND GAS PRODUCTION COULD BE MATERIALLY HARMED IF WE FAIL TO OBTAIN ADEQUATE SERVICES SUCH AS TRANSPORTATION AND PROCESSING. The sale of our oil and gas production depends on a number of factors beyond our control, including the availability and capacity of transportation and processing facilities. Our failure to obtain such services on acceptable terms could materially harm our business. 10 11 THE OIL AND GAS RESERVES DATA AND FUTURE NET REVENUES ESTIMATES WE REPORT ARE UNCERTAIN. Estimates of reserves by necessity are projections based on engineering data, the projection of future rates of production and the timing of future expenditures. Estimates of our proved oil and gas reserves and projected future net revenues are based on reserve reports which we prepare and a portion of which are reviewed by independent petroleum engineers. The process of estimating oil and gas reserves requires substantial judgment on the part of the petroleum engineers, resulting in imprecise determinations, particularly with respect to new discoveries. Different reserve engineers may make different estimates of reserve quantities and revenues attributable thereto based on the same data. Future performance that deviates significantly from the reserve reports could have a material adverse effect on us. The accuracy of any reserve estimate depends on the quality of the available data as well as engineering and geological interpretation and judgment. Results of drilling, testing and production and changes in the assumptions regarding decline and production rates, the ability to market oil and gas that is produced, oil and gas prices, revenues, taxes, capital expenditures, operating expenses, geologic success and quantities of recoverable oil and gas may vary substantially from those assumed in the estimates, may result in revisions to such estimates and could materially affect the estimated quantities and related value of reserves. The estimates of future net revenues reflect oil and gas prices as of the date of estimation, without escalation or reduction. Fluctuations in the price of natural gas and oil have the effect of significantly altering reserve estimates as the economic projections inherent in the estimates may reduce or increase the quantities of recoverable reserves. There can be no assurance, however, that such prices will be realized or that the estimated production volumes will be produced during the periods indicated. Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves most likely will vary from our estimates. IF WE FAIL TO ACQUIRE OR FIND ADDITIONAL RESERVES, OUR RESERVES AND PRODUCTION WILL DECLINE MATERIALLY FROM THEIR CURRENT LEVELS. The rate of production from oil and gas properties generally declines as reserves are depleted. Except to the extent that we acquire additional properties containing proved reserves, conduct successful exploration and development activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline materially as reserves are produced. Future oil and gas production is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves. WE INCUR CERTAIN COSTS TO COMPLY WITH GOVERNMENT REGULATIONS, ESPECIALLY REGULATIONS RELATING TO ENVIRONMENTAL PROTECTION, AND COULD INCUR EVEN GREATER COSTS IN THE FUTURE. Our exploration, production and marketing operations are regulated extensively at the federal, state and local levels, as well as by other countries in which we do business. We have made and will continue to make expenditures in our efforts to comply with the requirements of environmental and other regulations. Further, the oil and gas regulatory environment could change in ways that might substantially increase these costs. Hydrocarbon-producing states regulate conservation practices and the protection of correlative rights. These regulations affect our operations and limit the quantity of hydrocarbons we may produce and sell. In addition, at the U.S. federal level, the Federal Energy Regulatory Commission regulates interstate transportation of natural gas under the Natural Gas Act. Other regulated matters include marketing, pricing, transportation and valuation of royalty payments. As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state, local and foreign regulations relating to discharge of materials into, and 11 12 protection of, the environment. These regulations may, among other things, impose liability on us for the cost of pollution clean-up resulting from operations, subject us to liability for pollution damages, and require suspension or cessation of operations in affected areas. Changes in or additions to regulations regarding the protection of the environment could hurt our business. OUR INDUSTRY IS VERY COMPETITIVE. The oil and gas industry is extremely competitive. This is especially true with regard to exploration for, and exploitation and development of, new sources of crude oil and natural gas. As an independent oil and gas company, we frequently compete against other companies that are larger and financially stronger in acquiring properties suitable for exploration, in contracting for drilling equipment and other services and in securing trained personnel. WE DO NOT INSURE AGAINST ALL POTENTIAL LOSSES AND COULD BE SERIOUSLY HARMED BY UNEXPECTED LIABILITIES. Exploration for and production of oil and gas can be hazardous, involving natural disasters and other unforeseen occurrences such as blowouts, cratering, fires and loss of well control, which can damage or destroy wells or production facilities, injure or kill people, and damage property and the environment. 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. We maintain insurance against many, but not all, potential losses or liabilities arising from our operations in accordance with customary industry practices and in amounts that we believe to be prudent. Losses and liabilities arising from such events could reduce our revenues and increase our costs to the extent not covered by insurance. The occurrence of any of the aforementioned events and any payments made as a result of such events and the liabilities related thereto, would reduce the funds available for exploration, drilling and production and could have a material adverse effect on our financial position or results of operations. OUR HEDGING ACTIVITIES MAY PREVENT US FROM BENEFITING FROM PRICE INCREASES AND MAY EXPOSE US TO OTHER RISKS. We engage in price risk management activities from time to time primarily for non-trading and to a lesser extent for trading purposes. We use derivative financial instruments (primarily price swaps and costless collars) for non-trading purposes to hedge the impact of market fluctuations on natural gas and crude oil market prices and net income and cash flow. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of price increases above the levels of the hedges. In addition, we are subject to risks associated with differences in prices at different locations, particularly where transportation constraints restrict our ability to deliver oil and gas volumes to the delivery point to which the hedging transaction is indexed. Further, hedging contracts are subject to the risk that the other party may prove unable or unwilling to perform its obligations under such contracts. Any significant nonperformance could adversely affect us financially. WHEN WE ACQUIRE OIL AND GAS PROPERTIES, OUR FAILURE TO FULLY IDENTIFY POTENTIAL PROBLEMS, TO PROPERLY ESTIMATE RESERVES OR PRODUCTION RATES OR COSTS, OR TO EFFECTIVELY INTEGRATE THE ACQUIRED OPERATIONS COULD SERIOUSLY HARM US. We from time to time acquire oil and gas properties. When we do so, our failure to fully identify potential problems, to properly estimate reserves or production rates or costs, or to effectively integrate the acquired operations could seriously harm us. Although we perform reviews of acquired properties that we believe are consistent with industry practices, we do not review in depth every individual property involved in each acquisition. Ordinarily we focus on higher-value properties and sample the remainder. 12 13 However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume environmental and other risks and liabilities in connection with acquired properties. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and actual future production rates and associated costs with respect to acquired properties. Actual results may vary substantially from those assumed in the estimates. In addition, acquisitions may have adverse effects on our operating results, particularly during the periods in which the operations of acquired businesses are being integrated into our ongoing operations. OUR NON-U.S. OPERATIONS ARE SUBJECT TO RISKS OF DOING BUSINESS ABROAD. Our non-U.S. oil and natural gas exploration, exploitation, development and production activities are subject to certain political and economic risks including, among others: - cancellation or renegotiation of contracts; - disadvantages of competing against companies from countries that are not subject to U.S. laws and regulations, including the Foreign Corrupt Practices Act; - changes in foreign laws or regulations; - changes in tax laws; - royalty and tax increases; - retroactive tax claims; - expropriation or nationalization of property; - currency fluctuations; - foreign exchange controls; - import and export regulations; - environmental controls; - risks of loss due to civil strife, acts of war, guerilla activities and insurrection; and - other risks arising out of foreign governmental sovereignty over the areas in which our operations are conducted. Consequently, our non-U.S. exploration, exploitation, development and production activities may be substantially affected by factors beyond our control, any of which could materially adversely affect our financial position or results of operations. Furthermore, in the event of a dispute arising from non-U.S. operations, we may be subject to the exclusive jurisdiction of courts outside the United States or may not be successful in subjecting non-U.S. persons to the jurisdiction of the courts in the United States, which could adversely affect the outcome of the dispute. A DECLINE IN THE CONDITION OF THE CAPITAL MARKETS OR A SUBSTANTIAL RISE IN INTEREST RATES COULD HARM US. If the condition of the capital markets utilized by us to finance our operations materially declines, we might not be able to finance our operations on terms we consider acceptable. In addition, a substantial rise in interest rates would decrease our net cash flows available for reinvestment. OUR COMPUTER SYSTEMS OR OTHER ASSETS USED IN OUR OPERATIONS AND THOSE OF THIRD PARTIES MAY NOT BE YEAR 2000 COMPLIANT, WHICH MAY CAUSE SYSTEM FAILURES AND DISRUPTIONS IN OPERATIONS. The inability of some computer programs and embedded computer chips to distinguish between the year 1900 and the year 2000 poses a serious threat of business disruption to any organization that uses computer technology and computer chip technology in their business systems or equipment. Each major business unit has been required to 13 14 inventory and assess the risk associated with hardware, software, telecommunications systems, office equipment, embedded chip controls and systems, process control systems, facility control systems and dependencies on external mission critical entities. We presently believe that, with updates to software that are substantially complete or well under way, conversions to new software and completion of efforts planned by each major business unit to update imbedded microprocessors, the risk associated with year 2000 will be significantly reduced. However, we are unable to assure that the consequences of year 2000 failures of systems maintained by us or by third parties will not materially adversely impact our results of operations or financial condition. More detailed information about the year 2000 risks and our efforts to address this issue is contained in our Annual Report on Form 10-K for the year ended December 31, 1998, as amended by Amendment No. 1 on Form 10-K/A, and our Quarterly Report on Form 10-Q for the three-month and six-month periods ended June 30, 1999, both of which are incorporated by reference into this prospectus. 14 15 CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS This prospectus and the documents incorporated by reference contain 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. All statements other than statements of historical facts, including, among others, statements regarding our future financial position, business strategy, budgets, reserve information, projected levels of production, projected costs and plans and objectives of management for future operations, are forward-looking statements. We typically use words such as "expect", "anticipate", "estimate", "strategy", "intend", "plan" and "believe" or the negative of those terms or other variations of them or by comparable terminology to identify our forward-looking statements. In particular, statements, express or implied, concerning future operating results or the ability to generate income or cash flows are forward-looking statements. Although we believe our expectations reflected in forward-looking statements are based on reasonable assumptions, no assurance can be given that these expectations will be achieved. Important factors that could cause actual results to differ materially from the expectations reflected in the forward-looking statements include, among others: - timing and extent of changes in commodity prices for crude oil, natural gas and related products and interest rates; - extent of our success in discovering, developing, marketing and producing reserves and in acquiring oil and gas properties; - successful implementation of our Year 2000 Plan, the effectiveness of our Year 2000 Plan, and the Year 2000 readiness of outside entities; - political developments around the world; and - financial market conditions. Some of these factors are discussed under "Risk Factors" beginning on page 10 of this prospectus. In light of these risks, uncertainties and assumptions, the events anticipated by our forward-looking statements might not occur. We undertake no obligation to update or revise our forward-looking statements, whether as a result of new information, future events or otherwise. USE OF PROCEEDS We expect the net proceeds from the offering of common stock by EOG to be approximately $577.7 million after deducting discounts to the underwriters and estimated expenses of the offering that we will pay. We expect to use the net proceeds from the offering of common stock to repay a portion of the indebtedness incurred in connection with the Share Exchange to fund a cash capital contribution to our subsidiaries that conduct our India and China operations. The pending Share Exchange with Enron Corp. is discussed in "Prospectus Summary -- Share Exchange With Enron Corp." We will not receive any proceeds from the sale of our common stock by Enron Corp. or the underwriters' exercise of the over-allotment option. 15 16 CAPITALIZATION The following table sets forth as of June 30, 1999: - Our actual capitalization; - Our as-adjusted capitalization showing the effects of our receipt of the estimated net proceeds from the sale of the shares we are selling in this offering assuming that the net proceeds are used to repay outstanding commercial paper, bank debt and advances from affiliates; and - Our pro forma as-adjusted capitalization showing the effects of - our receipt of the estimated net proceeds from the sale of the shares we are selling in this offering; and - our receipt of 62,270,000 shares of our common stock currently owned by Enron Corp. in exchange for all the stock of our subsidiary, EOGI-India, Inc. after we have made, indirectly, a $600,000,000 cash capital contribution and a contribution of receivables due from subsidiaries of EOGI-India, Inc. as of June 30, 1999, funded in part from borrowings under a new credit facility. The as-adjusted capitalization and the pro forma as-adjusted capitalization assume that the net proceeds from the offering of the common stock are used to make capital contributions to our subsidiaries that conduct our India and China operations in connection with the pending Share Exchange. If the Share Exchange has already taken place when the offering is completed, the net proceeds would be used to repay a portion of the indebtedness incurred to fund such capital contribution.
JUNE 30, 1999 -------------------------------------- PRO FORMA ACTUAL AS ADJUSTED AS ADJUSTED ---------- ----------- ----------- (IN THOUSANDS) Long-term debt Company: Commercial paper and bank debt............ $ 293,643 $ - $ 343,643 Notes due 2004 (6.50%).................... 100,000 100,000 100,000 Notes due 2006 (6.70%).................... 150,000 150,000 150,000 Notes due 2007 (6.50%).................... 100,000 100,000 100,000 Notes due 2008 (6.00%).................... 175,000 175,000 175,000 Notes due 2028 (6.65%).................... 150,000 150,000 150,000 Subsidiary companies: Notes due 2001 (floating)................. 105,000 105,000 105,000 Other..................................... 240 240 240 Affiliates(1)................................ 66,000 - 66,000 ---------- ---------- ---------- Total long-term debt................. 1,139,883 780,240 1,189,883 Shareholders' equity Common stock................................. 201,600 201,870 201,870 Additional paid in capital................... 401,042 978,512 978,512 Unearned compensation........................ (4,183) (4,183) (4,183) Cumulative foreign currency translation adjustment................................ (26,124) (26,124) (26,124) Retained earnings............................ 854,846 854,846 1,366,152 Common stock held in treasury................ (117,137) (117,137) (1,502,645) ---------- ---------- ---------- Total shareholders' equity........... 1,310,044 1,887,784 1,013,582 ---------- ---------- ---------- Total capitalization................. $2,449,927 $2,668,024 $2,203,465 ========== ========== ==========
(1) Subsequent to June 30, 1999, we have repaid the advances from affiliates, and there are currently no amounts outstanding. 16 17 PRICE RANGE OF COMMON STOCK AND CASH DIVIDENDS The following table sets forth, for the periods indicated, the high and low sales prices per share for our common stock, as reported on the New York Stock Exchange Composite Tape, and the amount of cash dividends paid per share.
PRICE RANGE ---------------- CASH HIGH LOW DIVIDENDS ------ ------ --------- 1997 First Quarter....................................... $27.00 $19.88 $0.03 Second Quarter...................................... 21.75 17.50 0.03 Third Quarter....................................... 25.06 17.69 0.03 Fourth Quarter...................................... 23.81 18.50 0.03 1998 First Quarter....................................... $24.13 $18.56 $0.03 Second Quarter...................................... 24.50 18.13 0.03 Third Quarter....................................... 20.69 11.75 0.03 Fourth Quarter...................................... 18.50 12.69 0.03 1999 First Quarter....................................... $18.38 $15.69 $0.03 Second Quarter...................................... 21.50 16.00 0.03 Third Quarter(through August 10, 1999).............. 25.19 19.25 0.03
As of July 1, 1999, there were approximately 430 record holders of our common stock, including individual participants in security position listings. There are an estimated 20,000 beneficial owners of our common stock, including shares held in street name. We currently intend to continue to pay quarterly cash dividends on the 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, our financial condition, funds from operations, level of exploration, exploitation and development expenditure opportunities and future business prospects of EOG. 17 18 ENRON OIL & GAS COMPANY UNAUDITED CONDENSED CONSOLIDATED PRO FORMA FINANCIAL INFORMATION The following unaudited condensed consolidated pro forma statements of income for the year ended December 31, 1998 and the six months ended June 30, 1999, give effect to the offering and the Share Exchange as described below, as though they occurred on January 1, 1998. The unaudited condensed consolidated pro forma balance sheet at June 30, 1999 gives effect to the offering and the Share Exchange as though they occurred on June 30, 1999. The unaudited condensed consolidated pro forma statements of income and balance sheet have been prepared based upon our historical consolidated statements of income and balance sheet of EOG included in our Annual Report on Form 10-K for the year ended December 31, 1998, as amended by Amendment No. 1 on Form 10-K/A, and our Quarterly Report on Form 10-Q for the three-month and six-month periods ended June 30, 1999, both of which are incorporated by reference in this prospectus and have been prepared based upon available information and assumptions that our management believes are reasonable. The unaudited condensed consolidated pro forma statements of income are for informational purposes only, and do not necessarily represent what our actual results of operations would have been had the offering and the Share Exchange occurred on January 1, 1998. The unaudited condensed consolidated pro forma balance sheet is for informational purposes only, and does not purport to represent our actual financial position had the offering and the Share Exchange occurred on June 30, 1999. In addition, the unaudited condensed consolidated pro forma financial statements are not necessarily indicative of our future results of operations or financial position and should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Consolidated Financial Statements of EOG and the related notes included in our Annual Report on Form 10-K for the year ended December 31, 1998, as amended by Amendment No. 1 on Form 10-K/A, and our Quarterly Report on Form 10-Q for the three-month and six-month periods ended June 30, 1999, both of which are incorporated by reference in this prospectus. 18 19 UNAUDITED CONDENSED CONSOLIDATED PRO FORMA STATEMENT OF INCOME FOR THE SIX-MONTH PERIOD ENDED JUNE 30, 1999 (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
PRO FORMA HISTORICAL ADJUSTMENTS AS ADJUSTED ---------- ----------- ----------- NET OPERATING REVENUES Natural Gas Trade......................................... $244,775 $(25,920)(a) $218,855 Associated Companies(h)....................... 41,094 41,094 Crude Oil, Condensate and Natural Gas Liquids Trade......................................... 63,257 (14,349)(a) 48,908 Associated Companies(h)....................... 1,259 1,259 Losses on Sales of Reserves and Related Assets and Other, Net................................ (4,236) (4,236) -------- -------- -------- Total.................................... 346,149 (40,269) 305,880 OPERATING EXPENSES Lease and Well................................... 47,607 (7,145)(a) 40,462 Exploration Costs................................ 27,091 (1,647)(a) 25,444 Dry Hole Costs................................... 2,475 2,475 Impairment of Unproved Oil and Gas Properties.... 15,987 15,987 Depreciation, Depletion and Amortization......... 170,803 (5,811)(a) 164,992 General and Administrative....................... 50,019 (10,533)(a) 39,486 Taxes Other Than Income.......................... 26,076 (4,302)(a) 21,774 -------- -------- -------- Total.................................... 340,058 (29,438) 310,620 -------- -------- -------- OPERATING INCOME (LOSS)............................ 6,091 (10,831) (4,740) OTHER INCOME, NET.................................. 58,290 927(a) 59,217 -------- -------- -------- INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES.... 64,381 (9,904) 54,477 INTEREST EXPENSE Incurred Trade......................................... 35,208 1,868(b) 37,076 Affiliate(h).................................. 139 139 Capitalized...................................... (6,306) 2,100(a) (4,206) -------- -------- -------- Net Interest Expense.......................... 29,041 3,968 33,009 -------- -------- -------- INCOME BEFORE INCOME TAXES......................... 35,340 (13,872) 21,468 INCOME TAX PROVISION............................... 9,636 (3,657)(a) 5,325 (654)(b) -------- -------- -------- NET INCOME......................................... $ 25,704 $ (9,561) $ 16,143 ======== ======== ======== NET INCOME PER SHARE OF COMMON STOCK Basic............................................ $ 0.17 $ 0.14 ======== ======== Diluted.......................................... $ 0.17 $ 0.13 ======== ======== AVERAGE NUMBER OF COMMON SHARES Basic............................................ 153,779 118,509 ======== ======== Diluted.......................................... 154,943 119,673 ======== ========
The following notes are an integral part of these condensed consolidated pro forma financial statements. 19 20 UNAUDITED CONDENSED CONSOLIDATED PRO FORMA STATEMENT OF INCOME FOR THE YEAR ENDED DECEMBER 31, 1998 (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
PRO FORMA HISTORICAL ADJUSTMENTS AS ADJUSTED ---------- ----------- ----------- NET OPERATING REVENUES Natural Gas Trade............................................ $558,376 $(48,722)(a) $509,654 Associated Companies(h).......................... 62,929 62,929 Crude Oil, Condensate and Natural Gas Liquids Trade............................................ 120,366 (24,115)(a) 96,251 Associated Companies(h).......................... 9,266 9,266 Gains on Sales of Reserves and Related Assets and Other, Net....................................... 18,251 18,251 -------- -------- -------- Total....................................... 769,188 (72,837) 696,351 OPERATING EXPENSES Lease and Well...................................... 98,868 (11,119)(a) 87,749 Exploration Costs................................... 65,940 (2,532)(a) 63,408 Dry Hole Costs...................................... 22,751 22,751 Impairment of Unproved Oil and Gas Properties....... 32,076 32,076 Depreciation, Depletion and Amortization............ 315,106 (9,320)(a) 305,786 General and Administrative.......................... 69,010 (11,043)(a) 57,967 Taxes Other Than Income............................. 51,776 (6,615)(a) 45,161 -------- -------- -------- Total....................................... 655,527 (40,629) 614,898 -------- -------- -------- OPERATING INCOME...................................... 113,661 (32,208) 81,453 OTHER INCOME (EXPENSE), NET........................... (4,800) 5,106(a) 306 -------- -------- -------- INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES....... 108,861 (27,102) 81,759 INTEREST EXPENSE Incurred Trade............................................ 60,701 (99)(a) 65,134 4,532(b) Affiliate(h)..................................... 589 589 Capitalized......................................... (12,711) 3,978(a) (8,733) -------- -------- -------- Net Interest Expense............................. 48,579 8,411 56,990 -------- -------- -------- INCOME BEFORE INCOME TAXES............................ 60,282 (35,513) 24,769 INCOME TAX PROVISION (BENEFIT)........................ 4,111 (10,469)(a) (7,944) (1,586)(b) -------- -------- -------- NET INCOME............................................ $ 56,171 $(23,458) $ 32,713 ======== ======== ======== NET INCOME PER SHARE OF COMMON STOCK Basic............................................... $ 0.36 $ 0.27 ======== ======== Diluted............................................. $ 0.36 $ 0.27 ======== ======== AVERAGE NUMBER OF COMMON SHARES Basic............................................... 154,345 119,075 ======== ======== Diluted............................................. 155,054 119,784 ======== ========
The following notes are an integral part of these condensed consolidated pro forma financial statements. 20 21 UNAUDITED CONDENSED CONSOLIDATED PRO FORMA BALANCE SHEET AT JUNE 30, 1999 (IN THOUSANDS, EXCEPT SHARE AMOUNTS)
ADDITIONAL EXCHANGE OF BORROWINGS TRANSFERRED AND EQUITY SUBSIDIARIES OTHER HISTORICAL ISSUANCE SHARES ADJUSTMENTS AS ADJUSTED ----------- ---------- ------------ ----------- ----------- ASSETS CURRENT ASSETS Cash and Cash Equivalents.................. $ 11,411 $ 45,400(b) $ (606,287)(d) $(13,355)(f) $ 7,759 577,740(c) (10,000)(e) 2,850(g) Accounts Receivable Trade.................................... 159,469 (59,139)(d) 100,330 Associated Companies(h).................. 12,795 12,795 Inventories................................ 35,175 (10,058)(d) 25,117 Other...................................... 6,420 (1,354)(d) 5,066 ----------- -------- ----------- -------- ----------- Total................................ 225,270 623,140 (686,838) (10,505) 151,067 OIL AND GAS PROPERTIES (SUCCESSFUL EFFORTS METHOD).................................... 4,965,113 (262,085)(d) 4,703,028 Less: Accumulated Depreciation, Depletion and Amortization......................... (2,298,265) 19,933(d) (2,278,332) ----------- -------- ----------- -------- ----------- Net Oil and Gas Properties........... 2,666,848 (242,152) 2,424,696 OTHER ASSETS................................. 69,928 4,600(b) (1,188)(d) 73,340 ----------- -------- ----------- -------- ----------- TOTAL ASSETS................................. $ 2,962,046 $627,740 $ (930,178) $(10,505) $ 2,649,103 =========== ======== =========== ======== =========== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Accounts Payable Trade.................................... $ 119,664 $ (29,898)(d) $ 89,766 Associated Companies(h).................. 41,014 (8,352)(f) 32,662 Accrued Taxes Payable...................... 16,465 (1,685)(d) 29(f) 14,809 Dividends Payable.......................... 4,736 4,736 Other...................................... 17,608 (9,090)(d) 1,000(g) 9,518 ----------- -------- ----------- -------- ----------- Total................................ 199,487 (40,673) (7,323) 151,491 LONG-TERM DEBT Trade...................................... 1,073,883 50,000(b) 1,123,883 Affiliate.................................. 66,000 66,000 OTHER LIABILITIES Trade...................................... 19,004 1,850(g) 20,854 Associated Companies(h).................... 26,085 (8,352)(f) 17,733 DEFERRED INCOME TAXES........................ 265,444 (15,499)(d) 3,516(f) 253,461 DEFERRED REVENUES............................ 2,099 2,099 SHAREHOLDERS' EQUITY Common Stock, $.01 Par, 320,000,000 Shares Authorized and 160,000,000 Shares Issued Historical and 187,000,000 Shares Pro Forma.................................... 201,600 270(c) 201,870 Additional Paid In Capital................. 401,042 577,470(c) 978,512 Unearned Compensation...................... (4,183) (4,183) Cumulative Foreign Currency Translation Adjustment............................... (26,124) (26,124) Retained Earnings.......................... 854,846 521,502(d) (196)(f) 1,366,152 (10,000)(e) Common Stock Held in Treasury, 6,104,863 Shares Historical and 68,374,863 Shares Pro Forma................................ (117,137) (1,385,508)(d) (1,502,645) ----------- -------- ----------- -------- ----------- Total Shareholders' Equity........... 1,310,044 577,740 (874,006) (196) 1,013,582 ----------- -------- ----------- -------- ----------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY... $ 2,962,046 $627,740 $ (930,178) $(10,505) $ 2,649,103 =========== ======== =========== ======== ===========
The following notes are an integral part of these condensed consolidated pro forma financial statements. 21 22 NOTES TO UNAUDITED CONDENSED CONSOLIDATED PRO FORMA FINANCIAL STATEMENTS The following pro forma adjustments give effect to the sale by us of 27,000,000 shares of our common stock in this offering, additional borrowings of $50.0 million under new revolving credit facilities executed on July 28, 1999, and the Share Exchange (see note (a)), as though these transactions occurred on January 1, 1998 for income statement purposes, and give effect to these transactions as though they occurred on June 30, 1999 for balance sheet purposes. Our historical results were derived from our historical financial statements included in our Annual Report on Form 10-K for the year ended December 31, 1998, as amended by Amendment No. 1 on Form 10-K/A, and our Quarterly Report on Form 10-Q for the three-month and six-month periods ended June 30, 1999, both of which are incorporated by reference in this prospectus. (a) To reflect the elimination of the historical results of operations of EOGI-India, Inc., Enron Oil & Gas India Ltd., EOGI China Company, Enron Oil & Gas China Ltd., EOGI-China, Inc. and Enron Oil & Gas China International Ltd. (collectively referred to as the "Transferred Subsidiaries"), all wholly owned subsidiaries of EOG. All of EOG's interest in the common shares of each of the Transferred Subsidiaries is to be transferred to Enron Corp. in exchange for 62,270,000 shares of our common stock owned by Enron Corp. pursuant to a share exchange agreement (the "Share Exchange"). (b) To reflect the borrowing of $50.0 million under a new revolving credit facility. Borrowings are assumed to be at 6.0% per annum, plus the amortization of commitment fees of $4.6 million ($1.5 million for 1998 and $0.4 million for the six months ended June 30, 1999). Commitment fees are deferred as "Other Assets" and are amortized over the related commitment or loan period, as applicable. (c) To reflect the net proceeds of $577.7 million received from the offering of 27,000,000 shares of our common stock. (d) To reflect the elimination of the balances of the Transferred Subsidiaries and the receipt of 62,270,000 shares of our common stock pursuant to the Share Exchange. The shares of our common stock received are reflected at their estimated fair market value on the date of the transfer and a gain is reflected for the difference between the fair market value of our shares of common stock received and our historical cost basis in the Transferred Subsidiaries. The estimated fair market value is based on an assumed market price per share of $22.250. The actual market price per share on the date of the Share Exchange may differ significantly from our estimate. Prior to the Share Exchange EOG will contribute to the transferred subsidiaries $600.0 million in the form of cash capital contributions plus contributions of net intercompany accounts receivable of $173.2 million at June 30, 1999. The actual balance of net intercompany accounts receivable on the date of the Share Exchange may differ significantly from the balance at June 30, 1999. The Share Exchange is in the form of a non-taxable exchange of shares; accordingly, no income taxes have been provided with respect to the recognized gain. (e) To reflect $10.0 million of transaction costs directly related to the Share Exchange. As noted in footnote(d), the Share Exchange is in the form of a non-taxable exchange of shares; accordingly, such transaction costs are not deductible for income tax purposes. (f) To reflect a net payment of $13.4 million from EOG to Enron Corp. to settle amounts payable to Enron Corp. and other income tax related issues, which were resolved as part of the Share Exchange and the termination of the Tax Sharing Agreement, as amended, between EOG and Enron Corp. 22 23 (g) To reflect the payment by Enron Corp. of $1.9 million and the assumption by EOG of a liability of the same amount related to certain unvested benefit obligations under an Enron Corp. Cash Balance Plan and the payment by Enron Corp. of $1.0 million and the assumption by EOG of a liability of the same amount related to employee medical reimbursement accounts concurrent with the loss of control of EOG by Enron Corp. (h) Associated companies and affiliate balances result from transactions with Enron Corp., its subsidiaries or affiliates. If as a result of the offering and the Share Exchange, Enron Corp.'s ownership of our common stock declines to a level that Enron Corp. accounts for its investment in EOG on the cost method, any balances with associated companies or affiliates would be reclassified as trade. 23 24 BUSINESS GENERAL Enron Oil & Gas Company, a Delaware corporation organized in 1985, together with its subsidiaries, explores, develops, produces and markets, natural gas and crude oil primarily in major producing basins in the United States, as well as in Canada and Trinidad and, to a lesser extent, selected other international areas. Our principal producing areas are further described under "Exploration and Production" below. At December 31, 1998, our estimated net proved natural gas reserves were 5,229 Bcf, including 1,180 Bcf of proved undeveloped methane reserves in the Big Piney deep Paleozoic formations, and estimated net proved crude oil, condensate and natural gas liquids reserves were 105 MMBbl. (See "-- Oil and Gas Exploration and Production Properties and Resources".) After giving effect to the Share Exchange, at December 31, 1998 our estimated net proved reserves would have been 4,294 Bcf of gas and 61 MMBbl of oil. After giving effect to the Share Exchange at December 31, 1998, 66% of our reserves, on a natural gas equivalent basis, was located in the United States, 11% in Canada and 23% in Trinidad. BUSINESS STRATEGY Our strategy is to maximize the return on invested capital by achieving operating and finding costs that are among the lowest in the industry. We are focused on growing our domestic natural gas reserves and production by concentrating our efforts in known North American reserve basins. We focus on selected international opportunities where we can successfully apply our core competencies in the exploitation of reserves. Our strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost effective basis. Our North American operations are organized into seven largely autonomous business units, each focusing on a basin or basins, utilizing personnel who have developed experience and expertise unique to the geology of the region, thereby leveraging our knowledge and cost structure into enhanced returns on invested capital. We focus our drilling activity toward natural gas deliverability in addition to natural gas reserve enhancement and to a lesser extent crude oil exploitation. We also focus on the cost-effective utilization of advances in technology associated with gathering, processing and interpretation of 3-D seismic data, developing reservoir simulation models and drilling operations through the use of new and/or improved drill bits, mud motors, mud additives, formation logging techniques and reservoir fracturing methods. These advanced technologies are used, as appropriate, throughout the company to reduce the risks associated with all aspects of oil and gas reserve exploration, exploitation and development. We implement our strategy by emphasizing the drilling of internally generated prospects in order to find and develop low cost reserves. We also make selected tactical acquisitions that give us additional economies of scale or land positions with significant additional prospects. Achieving and maintaining the lowest possible operating cost structure are also important goals in the implementation of our strategy. Consistent with our desire to optimize the use of our assets, we also sell selected oil and gas properties that for various reasons may no longer fit into future operating plans or which we believe do not have sufficient future growth potential. We do this when we believe the economic value to be obtained by selling the properties and reserves in the ground is greater than what we would obtain by holding the properties and producing the reserves over time. As a result, we typically receive each year a varying but substantial level of proceeds related to such sales. We use these proceeds for general corporate purposes. 24 25 With respect to information on our 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 our working interest in the wells or acreage. Unless otherwise defined, all references to wells are gross. BUSINESS SEGMENTS Our operations are all oil and gas exploration and production related. We have not included a discussion of our India and China operations since they will be transferred to Enron Corp. in connection with the Share Exchange. EXPLORATION AND PRODUCTION NORTH AMERICA OPERATIONS United States. Our 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 represented approximately 81% of our United States reserves (on a natural gas equivalent basis) and 82% of our United States net natural gas deliverability as of December 31, 1998. We operate substantially all of these properties. Our other United States oil and gas producing properties are located primarily in other areas of Texas, Utah, New Mexico, Oklahoma, California, Mississippi and Kansas. At December 31, 1998, 93% of our proved United States reserves, including the reserves in the Big Piney deep Paleozoic formations in Wyoming (on a natural gas equivalent basis), was natural gas and 7% was crude oil, condensate and natural gas liquids. A substantial portion of our United States natural gas reserves is in long-lived fields with well-established production histories. We believe that opportunities exist to increase production in many of these fields through continued infill and other development drilling. Big Piney Area. Our largest reserve accumulation is located in the Big Piney area in Sublette and Lincoln counties in southwestern Wyoming. We are the holder of the largest productive acreage base in this area, with approximately 280,000 net acres under lease directly within field limits. We operate approximately 800 natural gas and crude oil wells in this area in which we own an 85% average working interest. Deliveries from the area net to us averaged 118 MMcf per day of natural gas and 4.0 MBbl per day of crude oil, condensate, and natural gas liquids in 1998. At December 31, 1998, natural gas deliverability net to us was approximately 110 MMcf per day. The current principal producing intervals are the Almy, Mesaverde and Frontier formations. The Frontier formation, which occurs at 6,500 to 10,000 feet, contains approximately 64% of our Big Piney proved developed reserves. We drilled 44 wells in the Big Piney area in 1998 and we plan to drill 50 wells during 1999. We have recorded as proved undeveloped reserves 1,180 Bcf of methane contained, along with high concentrations of carbon dioxide as well as small amounts of other gaseous substances, in the deep Wyoming Paleozoic (Madison) formation located under acreage we hold by production in the Big Piney area. In January 1999, we acquired certain adjacent Madison formation producing interests that include the rights to an agreement covering the processing of natural gas from such adjacent interests from the Madison formation through an existing plant operated by another company in the industry. South Texas Area. Our activities in South Texas are focused in the Lobo, Wilcox and Frio producing horizons. The principal areas of activity are in the Lobo and Wilcox Trends which occur primarily in Webb, Zapata and Duval counties, as well as the Frio Trend in Matagorda County. In Matagorda County, we completed two wells in 1998, each with a rate of 40 MMcf per day of natural gas and 2.0 MBbl per day of condensate. At December 31, 1998, we operated approximately 420 wells in the South Texas area, and production is primarily from the Frio, Wilcox and Lobo sands at 25 26 depths ranging from 5,000 to 16,000 feet. We have approximately 273,000 net leasehold acres and more than 40,000 net mineral fee acres in this area. Natural gas deliveries net to us averaged approximately 162 MMcf per day in 1998. At December 31, 1998, natural gas deliverability from this area net to us was approximately 182 MMcf per day. We drilled 47 wells in the South Texas area in 1998, acquired 758 square miles of new 3-D seismic and leased 64,500 net acres. We plan to drill 54 wells in 1999 and plan to maintain an active drilling program in South Texas for several years. East Texas Area. Our activities in the East Texas area are primarily in the Carthage field, located in Panola County, the North Milton field, located in northern Harris County, and the Stowell/Big Hill area, located in Jefferson and Chambers Counties. The Carthage field production is primarily from the Cotton Valley, Travis Peak and Pettit formations. At December 31, 1998, we held approximately 17,900 net acres under lease with an average 74% working interest in this area. We drilled 29 wells in the Carthage area in 1998 and we anticipate drilling 15 wells in this area during 1999. We have continued our activity in the North Milton area where we now operate 30 wells and hold a 100% working interest in the acreage. We expect to drill three additional wells during 1999. We drilled 10 wells in the Stowell/Big Hill area in 1998, and we are continuing expansion of the program in 1999. Net deliveries from the East Texas area averaged 56.4 MMcf per day of natural gas and 2.3 MBbl per day of crude oil, condensate and natural gas liquids in 1998. At December 31, 1998, deliverability from the area was approximately 80 MMcf per day of natural gas with 2.0 MBbl per day of crude oil, condensate and natural gas liquids both net to us. Offshore Gulf of Mexico Area. During 1998, we made a significant acquisition on the Outer-Continental Shelf of the Gulf of Mexico, purchasing a 19% working interest in the Matagorda Island 623 field which increased our natural gas deliveries, adding 55 MMcf per day net to us. Development of the Eugene Island 135 discovery continued with a third development well increasing our net field production to 17 MMcf per day and 760 barrels of condensate per day. At December 31, 1998, we held an interest in 184 blocks in the Offshore Gulf of Mexico area totaling approximately 544,000 net acres. Of these 184 blocks, located predominantly in federal waters offshore Texas and Louisiana, we operate 127. Natural gas deliveries from this area averaged 116 MMcf per day during 1998 net to us. A substantial portion of such deliveries was from interests in the Matagorda Island and Mustang Island areas of offshore Texas with significant volumes also coming from Eugene Island 135. During 1998, we participated in the drilling of 10 wells (3.9 net wells) in the Gulf of Mexico. In 1999, we anticipate participating in the drilling of four to six wells. Canyon/Strawn Trend Area. Our activities in this area have been concentrated in Crockett, Terrell and Val Verde Counties in Texas where we drilled 21 natural gas wells during 1998. We hold approximately 66,000 net acres and now operate approximately 350 natural gas wells in this area in which we own a 90% average working interest. Production is from the Canyon sands and Strawn limestone at depths from 5,500 to 12,500 feet. At December 31, 1998, natural gas deliverability net to us was approximately 35 MMcf per day. Sand Tank Area. The Sand Tank area located in Eddy County, New Mexico produces from the Chester, Morrow, and Atoka formations. Natural gas deliveries for 1998 averaged 16 MMcf per day and deliveries of crude oil, condensate and natural gas liquids averaged .3 MBbl per day in 1998 both net to us. At year end 1998, deliverability, net to us, was approximately 15 MMcf per day of natural gas and .2 MBbl per day of crude oil, condensate and natural gas liquids. We hold 14,000 net acres and have an average working interest of approximately 60%. In 1999, we plan to drill four wells in this stacked-pay area. Pitchfork Ranch Area. The Pitchfork Ranch area located in Lea County, New Mexico, produces primarily from the 26 27 Bone Spring, Wolfcamp, Atoka and Morrow formations. In 1998, deliveries net to us averaged 18 MMcf per day of natural gas and approximately 2.0 MBbl per day of crude oil, condensate and natural gas liquids. At December 31, 1998, deliverability net to us was approximately 21 MMcf per day of natural gas and 1.8 MBbl per day of crude oil, condensate and natural gas liquids. We hold approximately 34,000 net acres and are continuing to interpret a 3-D seismic survey shot over this entire area. We expect to maintain a drilling program in this area in 1999. Vernal Area. In the Vernal area, located primarily in Uintah County, Utah, we operate approximately 305 producing wells and presently control approximately 77,000 net acres. In 1998, natural gas deliveries net to us from the Vernal area averaged 21 MMcf per day. Deliverability at December 31, 1998, was approximately 26 MMcf per day. Production is from the Green River and Wasatch formations located at depths between 4,500 and 8,000 feet. We have an average working interest of approximately 60%. We anticipate numerous drilling opportunities will be available in this area in 1999. Canada. We are engaged in the exploration for and the exploitation, development, production and marketing of natural gas, natural gas liquids and crude oil in Western Canada, principally in the provinces of Alberta, Saskatchewan, and Manitoba. We conduct operations from offices in Calgary, Alberta, and produce natural gas and crude oil from five major areas. The Sandhills area in southwestern Saskatchewan is the largest single natural gas producing area in Canada for EOG. In 1998, we drilled 150 wells in the area and we acquired additional acreage and wells in the area resulting in peak deliverability of approximately 44 MMcf per day net to us at December 31, 1998. We plan to drill approximately 223 wells during 1999. At the end of 1999, we expect to realize 48 MMcf per day net deliverability. The Blackfoot area in southeastern Alberta is our second largest natural gas producing area in Canada. In 1998, we drilled 16 new wells and we performed numerous recompletions, workovers and facility optimizations resulting in deliverability of approximately 30 MMcf per day and 1.2 MBbl per day of crude oil and condensate net to us at December 31, 1998. We plan to drill approximately 50 Blackfoot wells during 1999. As a result, we expect the net deliverability from the Blackfoot area to increase to 40 MMcf per day at the end of 1999. Total Canadian natural gas deliverability net to us at December 31, 1998 was approximately 120 MMcf per day, and we held approximately 555,000 net undeveloped acres in Canada. Total Canadian natural gas deliveries net to us for 1998 averaged approximately 105 MMcf per day. OUTSIDE NORTH AMERICA OPERATIONS We have producing operations offshore Trinidad, and are evaluating and conducting exploration, exploitation and development in selected other international areas. Trinidad. In November 1992, we were awarded a 95% working interest concession in the South East Coast Consortium Block offshore Trinidad, encompassing three undeveloped fields, previously held by three government-owned energy companies. We have developed the Kiskadee field. We are developing the Ibis field and we anticipate that the Oilbird field will be developed over the next several years. We are using existing surplus processing and transportation capacity at the Pelican field facilities owned and operated by Trinidad and Tobago government-owned companies to process and transport the production. We are selling natural gas into the local market under a take-or-pay agreement with the National Gas Company of Trinidad and Tobago. In 1998, deliveries net to us averaged 139 MMcf per day of natural gas, which includes 24 MMcf per day of gas balancing volumes relating to a field allocation agreement, and 3.0 MBbl per day of crude oil and condensate. In 1995, we were awarded the right to develop the modified U(a) block near the South East Coast Consortium Block. We signed a production sharing contract with the Government of Trinidad and Tobago in 1996. Under the contract we committed to the acquisition of 3-D seismic data and the drilling 27 28 of three wells. The first well was drilled in 1998 and was successful, encountering over 400 feet of net pay, resulting in the largest exploration discovery in our history. We estimate the gross proved reserves of the discovery to be over 600 billion cubic feet equivalent. We expect to drill two significant exploratory wells in 1999. At December 31, 1998, we held approximately 144,000 net undeveloped acres in Trinidad. Venezuela. We were awarded exploration, exploitation and development rights for a block offshore the eastern state of Sucre, Venezuela in early 1996. We signed agreements with the government of Venezuela and other participants associated with a concession awarded in the Gulf of Paria East. We hold an initial 90% working interest in the joint venture and act as operator. We drilled one exploratory well during 1998 and encountered hydrocarbons. We are continuing to do additional evaluation work. Other International. We continue 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. We are also participating in discussions concerning the potential for natural gas development opportunities in Mozambique as well as other opportunities in Trinidad and other countries. (See "Relationship with Enron Corp." for a further discussion of the relationship between our company and Enron Corp. in the Mozambique project.) MARKETING Wellhead Marketing. We currently sell our North America wellhead natural gas production 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. We sell wellhead natural gas volumes from Trinidad at prices that are based on a fixed price schedule with annual escalations. We currently sell approximately 7% of our wellhead natural gas production to pipeline and marketing subsidiaries of Enron Corp. We believe that the terms of our transactions and agreements with Enron Corp. are at least as favorable to us as could be obtained from third parties. We sell substantially all of our wellhead crude oil and condensate under various terms and arrangements at market responsive prices. We currently sell approximately 1% of our wellhead crude oil and condensate production to subsidiaries of Enron Corp. Other Marketing. Enron Oil & Gas Marketing, Inc., one of our wholly-owned subsidiaries, is a marketing company engaging in various marketing activities. Both we and this subsidiary 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 our own production and arrange for any necessary transportation to the points of delivery. In addition, this subsidiary has purchased and constructed several small gathering systems in order to facilitate its entry into the gathering business on a limited basis. Both our company and this subsidiary use 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 our exposure to commodity price risks for both natural gas and crude oil and condensate wellhead prices. (See "-- Other Matters -- Risk Management".) In September 1992, we sold a volumetric production payment for $326.8 million to a limited partnership. Delivery obligations were terminated in December 1998. (See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Capital Resources and Liquidity -- Sale of Volumetric Production Payment" included in our Annual Report on Form 10-K for the year ended December 31, 1998, as amended by Amendment No. 1 on Form 10-K/A, which is incorporated by reference into this prospectus.) 28 29 In March 1995, in a series of transactions with Enron Corp., we exchanged all of our 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, we were relieved of all performance obligations associated with the Cogen Contracts. We 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 our net operating revenues and cash receipts during 1995 and 1996 of approximately $13 million and $7 million, respectively, with offsetting decreases in 1998 and 1999 versus that anticipated under the Cogen Contracts. 29 30 WELLHEAD VOLUMES AND PRICES, AND LEASE AND WELL EXPENSES The following table sets forth certain information regarding our wellhead volumes of and average prices for natural gas per Mcf, crude oil and condensate, and natural gas liquids per Bbl, and average lease and well expenses per Mcfe delivered during each of the three years in the period ended December 31, 1998 and the six months ended June 30, 1998 and 1999:
SIX MONTHS YEAR ENDED DECEMBER 31, ENDED JUNE 30, ------------------------ --------------- 1996 1997 1998 1998 1999 ------ ------ ------ ------ ------ VOLUMES (PER DAY) Natural Gas (MMcf) United States(1)...................................... 608 657 671 634 659 Canada................................................ 98 101 105 99 108 Trinidad.............................................. 124 113 139 121 141 India................................................. - 18 56 50 74 ------ ------ ------ ------ ------ Total............................................ 830 889 971 904 982 ====== ====== ====== ====== ====== Crude Oil and Condensate (MBbl) United States......................................... 9.2 11.7 14.0 12.4 13.1 Canada................................................ 2.4 2.5 2.6 2.6 2.7 Trinidad.............................................. 5.2 3.4 3.0 2.8 2.6 India................................................. 2.8 2.3 5.1 4.5 6.7 ------ ------ ------ ------ ------ Total............................................ 19.6 19.9 24.7 22.3 25.1 ====== ====== ====== ====== ====== Natural Gas Liquids (MBbl) United States......................................... 1.3 2.6 2.9 2.6 2.7 Canada................................................ 1.2 1.3 1.0 1.1 0.7 ------ ------ ------ ------ ------ Total............................................ 2.5 3.9 3.9 3.7 3.4 ====== ====== ====== ====== ====== AVERAGE PRICES Natural Gas ($/Mcf) United States(2)...................................... $ 2.04 $ 2.32 $ 1.93 $ 2.03 $ 1.80 Canada................................................ 1.15 1.43 1.40 1.40 1.51 Trinidad.............................................. 1.00 1.05 1.06 1.08 1.07 India................................................. - 2.79 2.41 2.63 1.95 Composite........................................ 1.78 2.07 1.78 1.87 1.67 Crude Oil and Condensate ($/Bbl) United States......................................... $21.88 $19.81 $12.84 $13.90 $13.91 Canada................................................ 18.01 17.16 11.82 12.77 13.03 Trinidad.............................................. 19.76 18.68 12.26 13.66 11.83 India................................................. 20.17 20.05 12.86 14.31 11.80 Composite........................................ 20.60 19.30 12.66 13.82 13.04 Natural Gas Liquids ($/Bbl) United States......................................... $14.67 $12.76 $ 8.38 $ 9.24 $ 8.15 Canada................................................ 9.14 8.94 5.32 5.48 5.83 Composite........................................ 11.99 11.54 7.56 8.15 7.68 LEASE AND WELL EXPENSES ($/MCFE) United States........................................... $ .19 $ .23 $ .22 $ .23 $ .20 Canada.................................................. .34 .39 .37 .40 .41 Trinidad................................................ .16 .16 .12 .13 .12 India................................................... .99 .64 .24 .30 .28 Composite........................................ .22 .26 .24 .25 .23
- --------------- (1) Includes 48 MMcf per day for the year ended December 31, 1996, 1997 and 1998 and for the six-month period ended June 30, 1998 delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended. Delivery obligations were terminated in December 1998. (2) Includes an average equivalent wellhead value of $1.17, $1.73 and $1.53 per Mcf for the year ended December 31, 1996, 1997 and 1998 and of $1.59 per Mcf for the six-month period ended June 30, 1998, respectively, for the volumes described in note (1), net of transportation costs. 30 31 COMPETITION We actively compete for reserve acquisitions and exploration/exploitation leases, licenses and concessions, frequently against companies with substantially larger financial and other resources. To the extent our exploration budget is lower than that of certain of our competitors, we 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, we face competition from other producers and suppliers, including competition from other world wide energy supplies, such as natural gas from Canada. OTHER MATTERS Risk Management. We engage in price risk management activities from time to time primarily for non-trading and to a lesser extent for trading purposes. We use derivative financial instruments (primarily price swaps and costless collars) for non-trading purposes to hedge the impact of market fluctuations of natural gas and crude oil market prices on net income and cash flow. At December 31, 1998, we had outstanding crude oil commodity price swap transactions, designated as hedges, covering approximately 700 MBbl of crude oil and condensate for 1999. The fair value of the positions was a net revenue increase of $4 million at December 31, 1998. At December 31, 1998, based on the portion of our anticipated natural gas volumes for 1999 for which prices have not, in effect, been hedged using NYMEX-related commodity market transactions and long-term marketing contracts, our net income and after-tax cash flow sensitivity to changing natural gas prices is approximately $18 million for each $.10 per Mcf change in average wellhead natural gas prices. While we are not affected as significantly by changing crude oil prices for those volumes not otherwise hedged, our net income and cash flow sensitivity is approximately $6 million for $1.00 per barrel change in average wellhead crude oil prices. Tight Gas Sand Tax Credits (Section 29) and Severance Tax Exemption. United States federal tax law provides a tax credit for production of certain fuels produced from nonconventional sources (including natural gas produced from tight formations), subject to a number of limitations. Fuels qualifying for the credit must be produced from a well drilled or a facility placed in service after November 5, 1990 and before January 1, 1993, and must be sold before January 1, 2003. The credit, which is currently approximately $.52 per 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 $49 per barrel in current dollars. Significant benefits from the tax credit have accrued and continue to accrue to us since a portion (and in some cases a substantial portion) of our natural gas production from wells drilled after November 5, 1990, and before January 1, 1993, on our leases in several of our significant producing areas qualify for this tax credit. Natural gas production from wells spudded or completed after May 24, 1989 and before September 1, 1996 in tight formations in Texas qualifies for a ten-year exemption, ending August 31, 2001, from severance taxes, subject to certain limitations. In 1995, the drilling qualification period was extended from September 1996 through August 2002, and the tax exemption was modified in a somewhat reduced form. In 1999, the drilling qualification period was extended eight years through August 2010. 31 32 OIL AND GAS EXPLORATION AND PRODUCTION PROPERTIES AND RESERVES The following table sets forth our net proved and proved developed reserves at December 31 for each of the four years in the period ended December 31, 1998, and the changes in the net proved reserves for each of the three years in the period then ended as estimated by our engineering staff. See "Risk Factors--The oil and gas reserves data and future net revenues estimates we report are uncertain". NET PROVED AND PROVED DEVELOPED RESERVE SUMMARY
UNITED STATES CANADA TRINIDAD INDIA OTHER TOTAL ------------- ------ -------- ------- ----- ------- Natural Gas(Bcf) Net proved reserves at December 31, 1995........ 2,654.1(1) 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(1) 320.9 370.2 199.6 - 3,637.2 Revisions of previous estimates............... (50.8) (1.5) (0.4) 25.1 - (27.6) Purchases in place............................ 60.0 67.6 - - - 127.6 Extensions, discoveries and other additions... 275.9 37.8 - 253.5 7.7 574.9 Sales in place................................ (17.7) (0.4) - - - (18.1) Production.................................... (229.1) (37.0) (41.0) (6.6) - (313.7) ------- ------ ------- ------- ----- ------- Net proved reserves at December 31, 1997........ 2,784.8(1) 387.4 328.8 471.6 7.7 3,980.3 Revisions of previous estimates............... (55.9) (2.5) 4.7 32.3 (0.4) (21.8) Purchases in place............................ 123.0 54.9 - - - 177.9 Extensions, discoveries and other additions... 272.8 62.9 693.8 340.9 103.0 1,473.4 Sales in place................................ (37.5) - - - - (37.5) Production.................................... (233.8) (38.5) (50.9) (20.2) - (343.4) ------- ------ ------- ------- ----- ------- Net proved reserves at December 31, 1998........ 2,853.4(1) 464.2 976.4 824.6 110.3 5,228.9 ======= ====== ======= ======= ===== ======= Liquids (MBbl)(2) Net proved reserves at December 31, 1995........ 25,399 6,585 6,870 11,542 - 50,396 Revisions of previous estimates............... 339 191 1,835 - - 2,365 Purchases in place............................ 312 2 - - - 314 Extensions, discoveries and other additions... 7,103 2,116 1,388 275 - 10,882 Sales in place................................ (447) (121) - - - (568) Production.................................... (3,830) (1,321) (1,925) (1,026) - (8,102) ------- ------ ------- ------- ----- ------- Net proved reserves at December 31, 1996........ 28,876 7,452 8,168 10,791 - 55,287 Revisions of previous estimates............... 3,515 225 (31) 19 - 3,728 Purchases in place............................ 127 1,123 - - - 1,250 Extensions, discoveries and other additions... 6,037 1,590 - 20,123 - 27,750 Sales in place................................ (1,683) - - - - (1,683) Production.................................... (5,223) (1,384) (1,236) (838) - (8,681) ------- ------ ------- ------- ----- ------- Net proved reserves at December 31, 1997........ 31,649 9,006 6,901 30,095 - 77,651 Revisions of previous estimates............... (152) (504) (1,049) 3,063 73 1,431 Purchases in place............................ 3,104 - - - - 3,104 Extensions, discoveries and other additions... 9,396 448 11,429 11,501 1,089 33,863 Sales in place................................ (1,039) - - - - (1,039) Production.................................... (6,131) (1,358) (1,077) (1,874) - (10,440) ------- ------ ------- ------- ----- ------- Net proved reserves at December 31, 1998........ 36,827 7,592 16,204 42,785 1,162 104,570 ======= ====== ======= ======= ===== =======
(Table continued on following page) 32 33
UNITED STATES CANADA TRINIDAD INDIA OTHER TOTAL ------------- ------ -------- ------- ----- ------- Bcf Equivalent (Bcfe) Net proved reserves at December 31, 1995........ 2,806.6(1) 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(1) 365.3 419.2 264.3 - 3,968.9 Revisions of previous estimates............... (29.8) (0.1) (0.5) 25.2 - (5.2) Purchases in place............................ 60.7 74.4 - - - 135.1 Extensions, discoveries and other additions... 312.1 47.4 - 374.2 7.7 741.4 Sales in place................................ (27.7) (0.4) - - - (28.1) Production.................................... (260.4) (45.3) (48.5) (11.7) - (365.9) ------- ------ ------- ------- ----- ------- Net proved reserves at December 31, 1997........ 2,975.0(1) 441.3 370.2 652.0 7.7 4,446.2 Revisions of previous estimates............... (57.0) (5.5) (1.7) 50.8 - (13.4) Purchases in place............................ 141.6 54.9 - - - 196.5 Extensions, discoveries and other additions... 329.2 65.6 762.4 409.9 109.5 1,676.6 Sales in place................................ (43.7) - - - - (43.7) Production.................................... (270.6) (46.6) (57.3) (31.4) - (405.9) ------- ------ ------- ------- ----- ------- Net proved reserves at December 31, 1998........ 3,074.5(1) 509.7 1,073.6 1,081.3 117.2 5,856.3 ======= ====== ======= ======= ===== ======= Net proved developed reserves at Natural Gas (Bcf) December 31, 1995............................. 1,218.1 310.1 233.9 - - 1,762.1 December 31, 1996............................. 1,325.7 319.5 370.2 124.6 - 2,140.0 December 31, 1997............................. 1,349.0 370.9 328.8 286.6 - 2,335.3 December 31, 1998............................. 1,429.7 387.4 283.0 407.4 - 2,507.5 Liquids(MBbl)(2) December 31, 1995............................. 19,977 6,505 5,607 11,542 - 43,631 December 31, 1996............................. 24,868 7,452 8,168 10,791 - 51,279 December 31, 1997............................. 27,707 8,885 6,901 23,322 - 66,815 December 31, 1998............................. 33,045 7,465 4,782 33,472 - 78,764 Bcf Equivalents December 31, 1995............................. 1,338.0 349.1 267.5 69.3 - 2,023.9 December 31, 1996............................. 1,474.9 364.2 419.2 189.3 - 2,447.6 December 31, 1997............................. 1,515.3 424.2 370.2 426.5 - 2,736.2 December 31, 1998............................. 1,628.0 432.1 311.7 608.2 - 2,980.0
- --------------- (1) Includes 1,180 Bcf of proved undeveloped methane reserves contained, along with high concentrations of carbon dioxide and other gases, in deep Paleozoic (Madison) formations in the Big Piney area of Wyoming. (2) Includes crude oil, condensate and natural gas liquids. 33 34 Acreage. The following table summarizes our developed and undeveloped acreage at December 31, 1998. Excluded is acreage in which our interest is limited to owned royalty, overriding royalty and other similar interests.
DEVELOPED UNDEVELOPED TOTAL --------------------- --------------------- --------------------- GROSS NET GROSS NET GROSS NET --------- --------- --------- --------- --------- --------- United States California............. 21,324 16,747 821,738 748,238 843,062 764,985 Texas.................. 413,305 220,075 637,850 513,807 1,051,155 733,882 Offshore Gulf of Mexico.............. 283,571 126,306 564,775 417,827 848,346 544,133 Wyoming................ 153,597 116,092 324,531 251,792 478,128 367,884 Oklahoma............... 188,963 104,633 122,848 87,264 311,811 191,897 Montana................ 119,686 1,651 146,013 103,779 265,699 105,430 New Mexico............. 71,945 35,091 106,133 64,232 178,078 99,323 Utah................... 74,454 50,311 40,873 27,205 115,327 77,516 Mississippi............ 5,144 5,052 43,174 42,950 48,318 48,002 Kansas................. 17,339 15,489 6,747 4,009 24,086 19,498 Colorado............... 20,619 1,233 30,908 13,618 51,527 14,851 Louisiana.............. 6,285 5,429 6,520 3,767 12,805 9,196 Arkansas............... 8,522 1,319 2,457 2,010 10,979 3,329 Other.................. 5,247 984 1,015 795 6,262 1,779 --------- --------- --------- --------- --------- --------- Total.......... 1,390,001 700,412 2,855,582 2,281,293 4,245,583 2,981,705 Canada Saskatchewan........... 251,805 235,121 288,834 283,732 540,639 518,853 Alberta................ 372,612 243,225 336,713 243,971 709,325 487,196 Manitoba............... 11,743 9,954 23,730 21,966 35,473 31,920 British Columbia....... 656 164 8,755 5,553 9,411 5,717 --------- --------- --------- --------- --------- --------- Total Canada...... 636,816 488,464 658,032 555,222 1,294,848 1,043,686 Other International China.................. 5,000 5,000 1,844,531 1,844,531 1,849,531 1,849,531 Venezuela.............. - - 268,413 241,572 268,413 241,572 India.................. 98,300 29,490 564,307 169,292 662,607 198,782 France................. - - 168,032 168,032 168,032 168,032 Trinidad............... 4,200 3,990 147,233 143,490 151,433 147,480 --------- --------- --------- --------- --------- --------- Total Other International... 107,500 38,480 2,992,516 2,566,917 3,100,016 2,605,397 --------- --------- --------- --------- --------- --------- Total.......... 2,134,317 1,227,356 6,506,130 5,403,432 8,640,447 6,630,788 ========= ========= ========= ========= ========= =========
Producing Well Summary. The following table reflects the Company's ownership in gas and oil wells located in Texas, the Gulf of Mexico, Oklahoma, New Mexico, Utah, Wyoming, and various other states, Canada, Trinidad, India and China at December 31, 1998.
PRODUCTIVE WELLS EXCLUDING INDIA PRODUCTIVE WELLS AND CHINA ---------------- ---------------- GROSS* NET GROSS* NET ------- ------ ------- ------ Gas.................................................. 5,253 3,788 5,241 3,784 Oil.................................................. 897 506 831 486 ----- ----- ----- ----- Total...................................... 6,150 4,294 6,072 4,270 ===== ===== ===== =====
- --------------- * Gross gas and oil wells include 255 with multiple completions. 34 35 DRILLING AND ACQUISITION ACTIVITIES During the years ended December 31, 1996, 1997 and 1998, we spent approximately $599 million, $693 million and $769 million, respectively, for exploratory and development drilling and acquisition of leases and producing properties. We drilled, participated in the drilling of or acquired wells as set out in the table below for the periods indicated:
SIX MONTHS YEAR ENDED DECEMBER 31, ENDED JUNE 30, ------------------------------------------------ -------------- 1996 1997 1998 1999 -------------- -------------- -------------- -------------- GROSS NET GROSS NET GROSS NET GROSS NET ----- ------ ----- ------ ----- ------ ----- ------ Development Wells Completed North America Gas.......................... 396 325.04 467 352.90 478 402.80 158 119.47 Oil.......................... 80 57.46 94 74.85 38 34.98 32 28.24 Dry.......................... 80 68.77 101 80.01 79 62.16 35 30.65 --- ------ --- ------ --- ------ --- ------ Total................... 556 451.27 662 507.76 595 499.94 225 178.36 Outside North America Gas.......................... - - 12 3.60 - - 3 .90 Oil.......................... 1 .30 6 1.80 21 6.30 6 1.90 Dry.......................... - - - - - - - - --- ------ --- ------ --- ------ --- ------ Total................... 1 .30 18 5.40 21 6.30 9 2.80 --- ------ --- ------ --- ------ --- ------ Total Development....... 557 451.57 680 513.16 616 506.24 234 181.16 --- ------ --- ------ --- ------ --- ------ Exploratory Wells Completed North America Gas.......................... 14 10.36 8 5.12 5 4.40 8 5.95 Oil.......................... 1 .78 - - 6 5.50 - - Dry.......................... 26 19.00 12 7.53 22 15.70 7 5.05 --- ------ --- ------ --- ------ --- ------ Total................... 41 30.14 20 12.65 33 25.60 15 11.00 Outside North America Gas.......................... - - - - 1 1.00 - - Oil.......................... - - - - 1 .90 - - Dry.......................... 1 .50 - - - - - - --- ------ --- ------ --- ------ --- ------ Total................... 1 .50 - - 2 1.90 - - --- ------ --- ------ --- ------ --- ------ Total Exploratory....... 42 30.64 20 12.65 35 27.50 15 11.00 --- ------ --- ------ --- ------ --- ------ Total................... 599 482.21 700 525.81 651 533.74 249 192.16 Wells in Progress at end of period.......................... 87 61.08 44 36.39 28 15.73 54 42.33 --- ------ --- ------ --- ------ --- ------ Total................... 686 543.29 744 562.20 679 549.47 303 234.49 === ====== === ====== === ====== === ====== Wells Acquired Gas.......................... 350 148.20* 227 82.45* 333 317.23* 22 2.13* Oil.......................... 5 .65 48 20.50* - 1.70* 2 .67 --- ------ --- ------ --- ------ --- ------ Total................... 355 148.85 275 102.95 333 318.93 24 2.80 === ====== === ====== === ====== === ======
- --------------- * Includes the acquisition of additional interests in certain wells in which we previously owned an interest. All of our drilling activities are conducted on a contract basis with independent drilling contractors. We own no drilling equipment. 35 36 MANAGEMENT DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The directors and executive officers of EOG (upon the closing of the Share Exchange with Enron Corp., except as otherwise described below) and their names and ages are as follows (all positions are with EOG unless otherwise noted):
NAME AGE POSITION ---- --- -------- Fred C. Ackman........................ 68 Director Edward Randall, III................... 72 Director Frank G. Wisner....................... 61 Director Forrest E. Hoglund.................... 66 Chairman of the Board; Director Mark G. Papa.......................... 52 President and Chief Executive Officer; Director Edmund P. Segner, III................. 45 Vice Chairman and Chief of Staff Loren M. Leiker....................... 45 Executive Vice President, Exploration Gary L. Thomas........................ 49 Executive Vice President, North American Operations Barry Hunsaker, Jr. .................. 49 Senior Vice President and General Counsel Walter C. Wilson...................... 56 Senior Vice President and Chief Financial Officer
Mr. Ackman has been a director since 1989. He also has been a consultant to the oil and gas industry for over six years and has interests in ranching and investments. Mr. Randall has been a director since 1990, and his principal occupation is investments. Mr. Randall also is a director of KN Energy, Inc. and PaineWebber Group Inc. Mr. Wisner has been a director since 1997. He also has served as Vice Chairman of American International Group Inc. since 1997 following his retirement as U.S. Ambassador to India. American International Group Inc. is an insurance company, which provides insurance to companies investing in foreign operations. Mr. Wisner's more than 35-year career with the U.S. State Department, primarily in Africa, Asia and Washington, D.C., included serving as U.S. Ambassador to the Philippines, Egypt and Zambia. Forrest E. Hoglund joined EOG as Chairman of the Board and Director in September 1987. He also served as Chief Executive Officer of EOG until September 1998 and served as President from May 1990 until December 1996. Mr. Hoglund is an advisory director of Chase Bank of Texas, National Association. Mr. Hoglund expects to retire effective August 15, 1999 and, therefore, will not be a director or executive officer of EOG at the time of the closing of this offering. Mark G. Papa was elected President and Chief Executive Officer and Director of EOG in September 1998, President and Chief Operating Officer in September 1997, President in December 1996 and was President North America Operations from February 1994 to September 1998. From May 1986 through January 1994, Mr. Papa served as Senior Vice President - Operations. Mr. Papa joined Belco Petroleum Corporation, a predecessor of EOG, in 1981. We expect that Mr. Papa will be elected Chairman of the Board following Mr. Hoglund's retirement. Edmund P. Segner, III became Vice Chairman and Chief of Staff of EOG in September 1997. Mr. Segner was a director of EOG from January 1997 to October 1997. Mr. Segner joined Enron Corp. in 1988 and 36 37 was Executive Vice President and Chief of Staff. We expect that Mr. Segner will be elected a director of EOG to fill the vacancy created by Mr. Hoglund's retirement. Loren M. Leiker joined EOG in April 1989 and has been Executive Vice President, Exploration since May 1998. Mr. Leiker was previously Senior Vice President, Exploration of EOG. Gary L. Thomas was elected Executive Vice President, North American Operations in May 1998. He was previously Senior Vice President and General Manager of EOG's Midland Division. Mr. Thomas joined a predecessor of EOG in July 1978. Barry Hunsaker, Jr. has been Senior Vice President and General Counsel since he joined EOG in May 1996. Prior to joining EOG, Mr. Hunsaker was a partner in the law firm of Vinson & Elkins L.L.P. Walter C. Wilson joined EOG in November 1987 and has been Senior Vice President and Chief Financial Officer since May 1991. THE SELLING STOCKHOLDER
BENEFICIAL OWNERSHIP BENEFICIAL OWNERSHIP AFTER STOCK OFFERING BEFORE STOCK OFFERING AND SHARE EXCHANGE(1)(2) ------------------------ SHARES TO ------------------------ SELLING STOCKHOLDER SHARES PERCENTAGE BE SOLD(1) SHARES PERCENTAGE - ------------------- ---------- ---------- ---------- ---------- ---------- Enron Corp. 82,270,000 53.5% 8,500,000 11,500,000 9.7%
- --------------- (1) Assumes the exercise of the over-allotment option in full, and the transfer by Enron Corp. of 62,270,000 shares of our common stock to us in connection with the Share Exchange. (2) Concurrently with this offering, Enron Corp. is offering Exchangeable Notes, which are mandatorily exchangeable into no more than 10,000,000 shares of our common stock (no more than 11,500,000 shares if the over-allotment option to the underwriters in the Exchangeable Notes offering is exercised in full) owned by Enron Corp. Following consummation of the Exchangeable Notes offering, the shares that may be delivered upon exchange therefor will continue to be beneficially owned by Enron Corp. until such time as they are delivered at maturity of the Exchangeable Notes. If the underwriters' over-allotment options in this offering and the Exchangeable Notes offering are exercised in full and the maximum number of shares of common stock are delivered at maturity of the Exchangeable Notes, Enron Corp. will no longer own any shares of our common stock. The registration related to our common stock covered by the over-allotment option and our common stock deliverable upon exchange of the Exchangeable Notes is being provided pursuant to the terms of a stock restriction and registration agreement with Enron Corp., under which we have agreed that, upon the request of Enron Corp. (or certain assignees), we will register under the Securities Act and applicable state securities laws the sale of our common stock owned by Enron Corp. Our obligation is subject to certain limitations relating to a minimum amount of our common stock required for registration, the timing of registration and other similar matters. We are obligated to pay all expenses incidental to such registration, excluding underwriters' discounts and commissions and certain legal fees and expenses. RELATIONSHIP WITH ENRON CORP. After the Share Exchange and consummation of this offering, Enron Corp.'s ownership of EOG will be reduced to 16,000,000 shares of common stock (11,500,000 shares if the underwriters' over-allotment option in this offering is exercised in full). The Share Exchange Agreement provides that Enron Corp. may not sell these remaining shares of EOG common stock for a period of six months after the Share Exchange. However, Enron Corp. may sell convertible securities that would be 37 38 mandatorily exchangeable into a maximum of 10,000,000 of its remaining EOG shares (11,500,000 if the underwriters' over-allotment option in that offering is exercised in full). (See "The Selling Stockholder".) Enron Corp.'s sale of these convertible securities is discussed further in "Concurrent Offering". On closing of the Share Exchange, the EOG board of directors will be reduced to five, and all of Enron Corp.'s officers and directors currently serving as EOG directors will resign from the EOG board. We have the right to use the name "Enron Oil & Gas Company" for the period of six months after the Share Exchange. However, some time soon after the Share Exchange, we expect to change our corporate name to "EOG Resources, Inc." We will also change the names of our subsidiaries to reflect our new corporate name. Enron Corp. currently provides us with various services, such as maintenance of employee benefit plans, provision of some telecommunications and computer support services, lease of office space and the provision of some purchasing and operating services and other corporate staff and support services. After the Share Exchange, we have the right to continue to use these services for a period of up to one year. However, we expect to transition away from using these services as soon as reasonably convenient for both Enron Corp. and us. EOG believes that it has obtained these services at substantially market terms, and, therefore, we expect that our costs to obtain these services from third parties will not materially change. EOG and Enron Corp. have in the past entered into material transactions and agreements incident to their respective businesses. Such transactions and agreements have related to, among other things, the purchase and sale of natural gas and crude oil and hedging and trading activities. Those transactions and agreements currently in place will continue after the Share Exchange, and we do not expect any material changes to such transactions and agreements that would not otherwise occur in a third party transaction. EOG and Enron Corp. may enter into similar types of transactions and agreements in the future. We intend that the terms of any future transactions and agreements between us and Enron Corp. will be at least as favorable to us as could be obtained from other third parties. After the completion of the Share Exchange, we and Enron Corp. can compete anywhere in the world, including India and China. In certain areas of the world, affiliate rules may have prevented us from having exploration and production opportunities while Enron Corp. owned a majority of our common stock. After the Share Exchange, those rules will no longer restrict us. EOG and Enron Corp. have entered into an agreement regarding the manner in which they will share the burdens and benefits of the integrated project under joint development in Mozambique. The agreement provides generally that our interest in this project will be 20% of the combined ownership interest of EOG and Enron Corp. This agreement will continue in place after the Share Exchange. For further detail of our relationship with Enron Corp. after the Share Exchange and the status of specific intercompany agreements, please refer to the Share Exchange Agreement filed as an exhibit to the registration statement that includes this prospectus. 38 39 DESCRIPTION OF CAPITAL STOCK AUTHORIZED AND OUTSTANDING CAPITAL STOCK Our authorized capital stock consists of 10,000,000 shares of preferred stock, par value $.01 per share, none of which are outstanding, and 320,000,000 shares of common stock, $.01 par value, of which 153,896,229 shares were outstanding as of July 1, 1999. Following the Share Exchange and the offering, there will be 35,270,000 fewer shares of common stock outstanding. The following description of our capital stock summarizes the material terms and provisions of these securities. For the complete terms of our common stock and preferred stock, please refer to our restated certificate of incorporation and bylaws that are incorporated by reference into the registration statement that includes this prospectus. PREFERRED STOCK Our board of directors is authorized, subject to any limitations prescribed by law, to provide for the issuance of the shares of preferred stock in series, by filing a certificate pursuant to the applicable laws of the State of Delaware to establish from time to time the number of shares to be included in each such series, and to fix the powers, designations, preferences, and relative, participating, optional or other rights, if any, of the shares of each such series and any qualifications, limitations, or restrictions thereof, all without stockholder approval. Any future issuance of preferred stock, while providing desired flexibility in connection with acquisitions and other corporate purposes, could adversely affect the voting power or other rights of holders of common stock and the likelihood that such holders will receive dividend payments and payments upon liquidation, and could have the effect of delaying, deferring or preventing a change of control of EOG. COMMON STOCK Our common stock possesses ordinary voting rights for the election of directors and in respect to other corporate matters, each share being entitled to one vote. There are no cumulative voting rights, meaning that the holders of a majority of the shares voting for the election of directors can elect all the directors if they choose to do so. Our common stock carries no preemptive rights and is not convertible, redeemable or assessable, or entitled to the benefits of any sinking fund. The holders of our common stock are entitled to dividends in such amounts and at such times as may be declared by the board of directors out of legally available funds. Upon liquidation or dissolution, holders of common stock are entitled to share ratably in all net assets available for distribution to stockholders after payment of any corporate debts and any liquidation preference established for any preferred stock. All outstanding shares of common stock are duly authorized, validly issued, fully paid and nonassessable. LISTING Our common stock is listed on the New York Stock Exchange. TRANSFER AGENT AND REGISTRAR The transfer agent and registrar of our common stock is First Chicago Trust Company of New York, Jersey City, New Jersey. LIMITATION ON DIRECTORS' LIABILITY Delaware corporation law authorizes corporations to limit or eliminate the personal liability of directors to corporations and their stockholders for monetary damages for breach of directors' fiduciary duty of care. The duty of care requires that, when acting on behalf of the corporation, directors must exercise an informed business judgment based on all material information reasonably available to them. Absent the limitations authorized by such laws, directors are accountable to corporations and their stockholders for monetary damages for conduct constituting gross negligence in the exercise of their duty of care. The Delaware laws enable corporations to limit available relief to equitable remedies such as injunction 39 40 or rescission. Our restated certificate of incorporation limits the liability of our directors to EOG or its stockholders (in their capacity as directors but not in their capacity as officers) to the fullest extent permitted by the Delaware law. Specifically, our directors will not be personally liable for monetary damages for breach of a director's fiduciary duty as a director, except for liability - for any breach of the director's duty of loyalty to the company or its stockholders, - for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, - for unlawful payments of dividends or unlawful stock repurchases or redemptions as provided in Section 174 of the Delaware General Corporation Law, or - for any transaction from which the director derived an improper personal benefit. This provision in our restated certificate of incorporation may have the effect of reducing the likelihood of derivative litigation against directors, and may discourage or deter stockholders or management from bringing a lawsuit against directors for breach of their duty of care, even though such an action, if successful, might otherwise have benefited us and our stockholders. 40 41 LEGAL MATTERS The validity of our common stock offered hereby will be passed upon for EOG by Barry Hunsaker, Jr., Esq., Senior Vice President and General Counsel, and for the underwriters by Bracewell & Patterson, L.L.P. Certain other matters will be passed on for EOG by Fulbright & Jaworski L.L.P. Mr. Hunsaker owns substantially less than 1% of the outstanding shares of our common stock. Bracewell & Patterson, L.L.P. provides services to us and our affiliates on matters unrelated to the offering of the common stock. EXPERTS The consolidated financial statements and schedule included in our Annual Report on Form 10-K for the year ended December 31, 1998 incorporated by reference in this prospectus and elsewhere in the registration statement have been audited by Arthur Andersen LLP, independent public accountants, as indicated in their report with respect thereto, and are incorporated by reference herein in reliance upon the authority of said firm as experts in accounting and auditing in giving said report. The letter report of DeGolyer and MacNaughton, independent petroleum consultants, included as an exhibit to our Annual Report on Form 10-K for the year ended December 31, 1998, and the estimates from the reports of that firm appearing in such Annual Report, are incorporated by reference herein on the authority of said firm as experts in petroleum engineering in giving such reports. 41 42 WHERE YOU CAN FIND MORE INFORMATION We file annual, quarterly and special reports, proxy statements and other information with the SEC. Our SEC filings are available to the public over the Internet at the SEC's web site at http://www.sec.gov. You may also read and copy any document we file at the SEC's public reference rooms located at: - 450 Fifth Street, N.W. Washington, D.C. 20549; - Seven World Trade Center New York, New York 10048; and - Northwest Atrium Center 500 West Madison Street Chicago, Illinois 60661. Please call the SEC at 1-800-SEC-0330 for further information on the public reference rooms and their copy charges. Our common stock has been listed and traded on the New York Stock Exchange since 1989. Accordingly, you may inspect the information we file with the SEC at the New York Stock Exchange, 20 Broad Street, New York, New York 10005. The SEC allows us to "incorporate by reference" the information we file with them, which means that we can disclose important information to you by referring you to those documents. The information incorporated by reference is an important part of this prospectus, and information that we file later with the SEC will automatically update and supersede this information. We incorporate by reference the documents listed below and any future filings made with the SEC under Sections 13(a), 13(c), 14 and 15(d) of the Securities Exchange Act of 1934 until we sell all of the common stock: - Our Annual Report on Form 10-K for the fiscal year ended December 31, 1998, as amended by Amendment No. 1 on Form 10-K/A; and - Our Quarterly Reports on Form 10-Q for the quarters ended March 31, 1999 and June 30, 1999. You may request a copy of these filings, excluding exhibits, at no cost by writing or telephoning Angus H. Davis, Corporate Secretary, at our principal executive office, which is: Enron Oil & Gas Company 1400 Smith Street Houston, Texas 77002 (713) 853-6161 YOU SHOULD RELY ONLY ON THE INFORMATION INCORPORATED BY REFERENCE OR PROVIDED IN THIS PROSPECTUS. WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE YOU WITH DIFFERENT INFORMATION. WE ARE NOT MAKING AN OFFER OF THE SECURITIES COVERED BY THIS PROSPECTUS WHERE THE OFFER IS NOT PERMITTED. YOU SHOULD NOT ASSUME THAT THE INFORMATION IN THIS PROSPECTUS OR IN ANY OTHER DOCUMENT INCORPORATED BY REFERENCE IN THIS PROSPECTUS IS ACCURATE AS OF ANY DATE OTHER THAN THE DATE ON THE FRONT OF THOSE DOCUMENTS. 42 43 UNDERWRITING EOG, Enron Corp. and the underwriters for the offering named below have entered into an underwriting agreement with respect to the shares being offered. Subject to certain conditions, each underwriter has severally agreed to purchase the number of shares indicated in the following table.
Number of Underwriters Shares ------------ ---------- Goldman, Sachs & Co. ....................................... 6,200,000 Banc of America Securities LLC.............................. 6,200,000 Dain Rauscher Wessels, a division of Dain Rauscher Incorporated.............................................. 3,100,000 Lehman Brothers Inc. ....................................... 3,100,000 Merrill Lynch, Pierce, Fenner & Smith Incorporated .................................. 3,100,000 PaineWebber Incorporated.................................... 3,100,000 Salomon Smith Barney Inc. .................................. 3,100,000 Warburg Dillon Read LLC..................................... 3,100,000 ---------- Total.................................................. 31,000,000 ==========
If the underwriters sell more shares than the total number set forth in the table above, the underwriters have an option to buy up to an additional 4,500,000 shares from Enron Corp. to cover such sales. They may exercise that option for 30 days. If any shares are purchased pursuant to this option, the underwriters will severally purchase shares in approximately the same proportion as set forth in the table above. The following table shows the per share and total underwriting discounts and commissions to be paid to the underwriters by EOG and Enron Corp. The amounts are shown assuming both no exercise and full exercise of the underwriters' option to purchase additional shares.
Paid By EOG -------------------------- No Full Exercise Exercise ----------- ----------- Per Share............ $ 0.83 $ 0.83 Total................ $22,410,000 $22,410,000
Paid By Enron Corp. -------------------------- No Full Exercise Exercise ----------- ----------- Per Share............ $ 0.83 $ 0.83 Total................ $ 3,320,000 $ 7,055,000
Shares sold by the underwriters to the public will initially be offered at the initial price to public set forth on the cover of this prospectus. Any shares sold by the underwriters to securities dealers may be sold at a discount of up to $0.50 per share from the initial price to public. Any such securities dealers may resell any shares purchased from the underwriters to certain other brokers or dealers at a discount of up to $0.10 per share from the initial price to public. If all the shares are not sold at the initial price to public, the representatives may change the offering price and the other selling terms. EOG, its directors and executive officers, except Mr. Hoglund, who expects to retire effective August 15, 1999, and Enron Corp. have agreed with the underwriters not to offer, sell, contract to sell or otherwise dispose of or hedge any shares of EOG common stock or securities convertible into or exchangeable for shares of EOG common stock during the period from the date of this prospectus continuing through the date 180 days after the date of this prospectus, except with the prior written consent of Goldman, Sachs & Co. This agreement does not apply to any existing employee benefit plans or the exercise of stock options pursuant to EOG's stock option plan. In connection with the offering, the underwriters may purchase and sell shares of EOG common stock in the open market. These transactions may include short sales, stabilizing transactions and purchases to cover positions created by short sales. Short sales involve the sale by the underwriters of a greater number of shares than they are U-1 44 required to purchase in the offering. Stabilizing transactions consist of certain bids or purchases made for the purpose of preventing or retarding a decline in the market price of the common stock while the offering is in progress. The underwriters also may impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the underwriters have repurchased shares sold by or for the account of such underwriter in stabilizing or short covering transactions. These activities by the underwriters may stabilize, maintain or otherwise affect the market price of the common stock. As a result, the price of the common stock may be higher than the price that otherwise might exist in the open market. If these activities are commenced, they may be discontinued by the underwriters at any time. These transactions may be effected on the New York Stock Exchange, in the over-the-counter market or otherwise. EOG estimates that its total expenses of the offering of common stock, excluding underwriting discounts and commissions, will be approximately $600,000. EOG and Enron Corp. have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make in respect thereof. The underwriters or their respective affiliates in the past have provided investment banking and/or commercial banking services and other financial services for us and our affiliates and have received compensation and expense reimbursement for these services. In the case of Goldman, Sachs & Co. and Banc of America Securities LLC, these services have included advice to us in connection with the Share Exchange. Further, we expect that any indebtedness we incur to fund the cash capital contribution in connection with the Share Exchange will be provided by affiliates of some of the underwriters, a portion of which will be repaid with the proceeds of this offering. The underwriters or their respective affiliates may in the future provide investment banking and/or commercial banking services and other financial services to us or our affiliates for which they will receive compensation and expense reimbursement. Our director Edward Randall, III is also a director of PaineWebber Group, Inc., an affiliate of PaineWebber Incorporated. U-2 45 - ------------------------------------------------------ ------------------------------------------------------ - ------------------------------------------------------ ------------------------------------------------------ No dealer, salesperson or other person is authorized to give any information or to represent anything not contained in this prospectus. You must not rely on any unauthorized information or representations. This prospectus is an offer to sell only the shares offered hereby, but only under circumstances and in jurisdictions where it is lawful to do so. The information contained in this prospectus is current only as of its date. --------------------- TABLE OF CONTENTS
Page ---- Prospectus Summary.................... 3 Risk Factors.......................... 10 Cautionary Statement Regarding Forward-Looking Statements.......... 15 Use of Proceeds....................... 15 Capitalization........................ 16 Price Range of Common Stock and Cash Dividends........................... 17 Unaudited Condensed Consolidated Pro Forma Financial Information......... 18 Business.............................. 24 Management............................ 36 The Selling Stockholder............... 37 Relationship with Enron Corp. ........ 37 Description of Capital Stock.......... 39 Legal Matters......................... 41 Experts............................... 41 Where You Can Find More Information......................... 42 Underwriting.......................... U-1
31,000,000 Shares ENRON OIL & GAS COMPANY Common Stock --------------- [ENRON LOGO] --------------- GOLDMAN, SACHS & CO. BANC OF AMERICA SECURITIES LLC DAIN RAUSCHER WESSELS A DIVISION OF DAIN RAUSCHER INCORPORATED LEHMAN BROTHERS MERRILL LYNCH & CO. PAINEWEBBER INCORPORATED SALOMON SMITH BARNEY WARBURG DILLON READ LLC - ------------------------------------------------------ ------------------------------------------------------ - ------------------------------------------------------ ------------------------------------------------------ -----END PRIVACY-ENHANCED MESSAGE-----