Annual Report (Form 10-K), fiscal year 1993

ITEM 1. BUSINESS
GENERAL
Enron Oil & Gas Company (the 'Company'), a Delaware corporation, is engaged in the exploration for, and the development and production of, natural gas and crude oil primarily in major producing basins in the United States and, to a lesser extent, in Canada, Trinidad and selected other international areas. At December 31, 1993, the Company's estimated net proved natural gas reserves were 1,772 billion cubic feet ('Bcf') and estimated net proved crude oil, condensate and natural gas liquids reserves were 20.9 million barrels ('MMBbl'). (See 'Supplemental Information to Consolidated Financial Statements'). At such date, approximately 78% of the Company's reserves (on a natural gas equivalent basis) was located in the United States, 16% in Canada and 6% in Trinidad. As of December 31, 1993, the Company employed approximately 690 persons.
The Company's core areas are the Big Piney area in Wyoming, South Texas primarily centered in the Lobo Trend area, the Matagorda Trend area located in federal waters offshore Texas and the Canyon Trend located in West Texas. The Company's other domestic natural gas and crude oil producing properties are located primarily in other areas of Texas, Utah, New Mexico, Oklahoma and California. The Company also has natural gas and crude oil producing properties located in western Canada, primarily in the provinces of Alberta, Saskatchewan and Manitoba, and in Trinidad. At December 31, 1993, 95% of the Company's proved domestic reserves (on a natural gas equivalent basis) was natural gas and 5% was crude oil, condensate and natural gas liquids. A substantial portion of the Company's natural gas reserves is in long-lived fields with well established production histories. The opportunity exists to increase production in many of these fields through infill drilling.
Enron Corp. currently owns 80% of the outstanding common stock of the Company. (See 'Relationship Between the Company and Enron Corp.').
Unless the context otherwise requires, all references herein to the Company include Enron Oil & Gas Company, its predecessors and subsidiaries. Unless the context otherwise requires, all references herein to Enron Corp. include Enron Corp., its predecessors and affiliates, other than the Company and its subsidiaries.
With respect to information on the Company's working interest in wells or acreage, 'net' oil and gas wells or acreage are determined by multiplying 'gross' oil and gas wells or acreage by the Company's working interest in the wells or acreage. Unless otherwise defined, all references to wells are gross.
BUSINESS SEGMENTS
The Company's operations are all natural gas and crude oil exploration and production related. Accordingly, such operations are classified as one business segment.
EXPLORATION AND PRODUCTION
The Company's six principal U.S. producing areas are the Big Piney area, South Texas area, Matagorda Trend area, Canyon Trend area, Pitchfork Ranch field and Vernal area. Properties in these areas comprised approximately 76% of the Company's domestic reserves (on a natural gas equivalent basis) and 83% of the Company's maximum domestic net natural gas deliverability as of December 31, 1993 and are substantially all operated by the Company. The Company also has operations in Canada and in Trinidad and is conducting exploration in selected other international areas.
BIG PINEY AREA. The Company's largest reserve accumulation is located in the Big Piney area in Sublette and Lincoln counties in southwestern Wyoming. The Company is the holder of the largest productive acreage base in this area, with approximately 200,000 net acres under lease directly within field limits. A portion of the natural gas production from new wells drilled during 1991 and 1992 on the Company's leases in the Big Piney area is classified as tight formation natural gas. (See 'Other
Matters - Tight Gas Sand Tax Credits (Section 29) and Severance Tax Exemption'). The Company operates approximately 461 natural gas wells in this area in which it owns a 91% average working interest. Production from the area net to the Company averaged 126 million cubic feet ('MMcf') per day of natural gas and 1.4 thousand barrels ('MBbl') per day of crude oil, condensate, and natural gas liquids in 1993. At December 31, 1993, maximum natural gas deliverability net to the Company was approximately 138 MMcf per day.
The current principal producing intervals are the Frontier and Mesaverde formations. The Frontier formation, which occurs at 6,500-10,000 feet, contains approximately 66% of the Company's current Big Piney reserves. The Company drilled 48 wells in the Big Piney area in 1993 and anticipates an active drilling program will continue for several years.
SOUTH TEXAS AREA. The Company's activities in South Texas are focused in the Wilcox, Expanded Wilcox, Frio and Lobo producing horizons. The primary area of activity is in the Lobo Trend which occurs primarily in Webb and Zapata counties.
The Company operates approximately 625 wells in the South Texas area. Production is primarily from the Lobo sand of the Wilcox formation at depths ranging from 7,000 to 11,000 feet. The Company has approximately 260,000 acres under lease in this area and a majority of the natural gas production from new wells drilled during 1991 and 1992 on Company leases in the South Texas Lobo area is classified as tight formation natural gas. (See 'Other Matters - Tight Gas Sand Tax Credits (Section 29) and Severance Tax Exemption'). Natural gas sales net to the Company averaged 225 MMcf per day in 1993. At December 31, 1993, maximum natural gas deliverability net to the Company was approximately 250 MMcf per day. The Company drilled 104 wells in the South Texas area in 1993 and anticipates an active drilling program will continue for several years.
MATAGORDA TREND AREA. The Company has an interest in several fields in the Matagorda Trend area, located 20 miles south of Port O'Connor, Texas in federal waters. The Company has a 78% working interest in Block 638 and a 92% working interest in Block 620. In Matagorda Blocks 555, 556, 700 and 713, the Company has an approximate 70%, 50%, 62% and 64% working interest, respectively. In addition, the Company has an approximate 82% and 50% working interest in Mustang Island Blocks 758 and 784, respectively. The Company operates all of the offshore tracts mentioned above. Natural gas sales from these areas net to the Company averaged 59 MMcf per day in 1993. At December 31, 1993, maximum natural gas deliverability net to the Company from these blocks was approximately 76 MMcf per day. The Company expects to maintain an active drilling program in the Gulf of Mexico during 1994.
CANYON TREND AREA. The Company has added approximately 90,000 acres in this area during the last five years. Activities have been concentrated in Sutton, Crockett and Terrell Counties, Texas where the Company drilled 324 natural gas wells during the period 1991 through 1993. The Company operates approximately 500 natural gas wells in this area in which it owns a 95% average working interest. Production is from the Canyon sands and Strawn limestone at depths from 5,500 to 9,500 feet. At December 31, 1993, maximum natural gas deliverability net to the Company was approximately 70 MMcf per day. The Company expects to maintain an active drilling program in the Canyon Trend area during 1994. (See 'Other Matters - Tight Gas Sand Tax Credits (Section 29) and Severance Tax Exemption').
PITCHFORK RANCH FIELD. The Pitchfork Ranch field located in Lea County, New Mexico, produces primarily from the Bone Spring, Atoka and Morrow formations. In 1993, natural gas sales net to the Company averaged 44 MMcf per day. At December 31, 1993, maximum natural gas deliverability net to the Company was approximately 46 MMcf per day. During 1993, the Company significantly increased reserves and deliverability through drilling and workovers. The Company expects to maintain an active drilling program in this field during 1994. (See 'Other Matters - Tight Gas Sand Tax Credits (Section 29) and Severance Tax Exemption').
VERNAL AREA. In the Vernal area, located primarily in Uintah County, Utah, the Company operates approximately 187 producing wells and presently controls approximately 75,000 net acres. A
majority of the natural gas production from new wells drilled during 1991 and 1992 on the Company's leases in the Vernal area is classified as tight formation natural gas. (See 'Other Matters - Tight Gas Sand Tax Credits (Section 29) and Severance Tax Exemption'). In 1993, natural gas sales from the Vernal area averaged 24 MMcf per day compared with approximately 29 MMcf per day maximum deliverability, both net to the Company. Production is from the Green River and Wasatch formations located at depths between 4,500-8,000 feet. The Company has an average working interest of approximately 60%. The Company drilled 14 wells in the Vernal area in 1993 and expects to maintain a comparable drilling program during 1994.
CANADA. The Company is engaged in the exploration for and the development and production of natural gas and crude oil and the operation of natural gas processing plants in western Canada, principally in the provinces of Alberta, Saskatchewan, and Manitoba. The Company conducts operations from offices in Calgary. Effective December 31, 1992, the Company consummated the acquisition of a natural gas property located in the Sandhills field in Saskatchewan. The property was further developed in 1993 through the drilling of 150 wells resulting in deliverability net to the Company from the Sandhills property of approximately 36 MMcf per day at December 31, 1993. Maximum Canadian natural gas deliverability net to the Company at December 31, 1993 was approximately 76 MMcf per day, and the Company held approximately 324,000 net undeveloped acres in Canada. The Company expects to maintain an active drilling program in Canada during 1994.
TRINIDAD. In November 1992, the Company was awarded a 95% working interest concession in the South East Coast Consortium Block offshore Trinidad, previously held by three government-owned energy companies. Three undeveloped fields containing crude oil and natural gas rich with condensate are scheduled for development over the next three to five years. Existing surplus processing and transportation capacity at the Pelican Field facilities owned and operated by Trinidadian companies is being used to process and transport the production. Natural gas is being sold into the local market under a take-or-pay agreement with the National Gas Company of Trinidad and Tobago. At December 31, 1993, maximum natural gas deliverability net to the Company was approximately 40 MMcf per day and the Company held approximately 74,000 net undeveloped acres in Trinidad. As a result of continued development activities, natural gas deliveries were averaging approximately 60 MMcf per day and condensate deliveries were averaging approximately 3.3 MBbl per day net to the Company as of mid-March 1994. The Company expects to maintain an active development drilling program in this area in 1994.
OTHER INTERNATIONAL. The Company continues to pursue selected other conventional natural gas and crude oil opportunities outside North America. In 1993, two unsuccessful wells were drilled in Malaysia and one in the United Kingdom North Sea area. During 1994, the Company will pursue other exploitation opportunities in countries where indigenous natural gas reserves have been identified, particularly where synergies in natural gas transportation, processing and power cogeneration can be optimized with other Enron Corp. affiliated companies. The Company currently is actively involved in an effort to obtain joint venture concessions involving two oil fields (Panna and Mukta) and one natural gas field (Tapti) offshore India in the Bombay High area. Resolution is anticipated by mid-1994.
In 1993, the Company continued expansion of its international opportunity portfolio in the coalbed methane recovery arena. In September 1992, the Company entered into an operating agreement under which it is serving as operator with another partner in a venture in the Lorraine Basin in France and under which it exercised, in March 1994, an option to acquire a 50% working interest in the concession. In addition, a 100% working interest concession has been obtained in the Galilee Basin in Queensland, Australia. Protocols have also been signed and joint venture agreements are in the government approval process in both Russia and Kazakhstan; joint feasibility studies are underway in China; and, several other high potential countries are under active investigation.
MARKETING
WELLHEAD MARKETING. The Company's wellhead natural gas production is currently being sold on the spot market and under long-term natural gas contracts at market responsive prices. In many instances, the long-term contract prices closely approximate the prices received for natural gas being sold on the spot market. Approximately one-half of the Company's wellhead natural gas production is currently being sold to pipeline and marketing subsidiaries of Enron Corp.
Substantially all of the Company's wellhead crude oil and condensate is sold under short-term contracts at market responsive prices.
OTHER MARKETING. Enron Oil & Gas Marketing, Inc. ('EOGM'), a wholly-owned subsidiary of the Company, is a marketing company engaging in various marketing activities. Both the Company and EOGM contract to provide, under long-term agreements, natural gas to various purchasers and then aggregate the necessary supplies for the sales with purchases from various sources including third-party producers, marketing companies, pipelines or from the Company's own production. In addition, EOGM has purchased and constructed several small gathering systems in order to facilitate its entry into the gathering business on a limited basis. EOGM anticipates providing gathering services when such activity will enhance its capability as an aggregator and marketer. Both EOGM and the Company utilize other short and long-term hedging mechanisms including sales and purchases in the futures market and price swap agreements. These marketing activities have provided an effective balance in managing the Company's exposure to commodity price risks in the energy market.
In September 1992, the Company sold a volumetric production payment for $326.8 million to a limited partnership of which an Enron Corp. affiliated company is general partner with a 1% interest. Under the terms of the production payment agreements, the Company conveyed a real property interest of approximately 124 billion cubic feet equivalent ('Bcfe') (136 trillion British thermal units) of natural gas and other hydrocarbons in the Big Piney area of Wyoming. Effective October 1, 1993, the agreements were amended providing for the extension of the original term of the volumetric production payment through March 31, 1999 and including a revised schedule of daily quantities of hydrocarbons to be delivered which is approximately one-half of the original schedule. The revised schedule will total approximately 89.1 Bcfe (97.8 trillion British thermal units) versus approximately 87.9 Bcfe (96.4 trillion British thermal units) remaining to be delivered under the original agreement. Daily quantities of hydrocarbons no longer required to be delivered under the revised schedule during the period from October 1, 1993 through June 30, 1996 are available for sale by the Company. The Company retains responsibility for its working interest share of the cost of operations. The Company also entered into a separate agreement with the same limited partnership whereby it has agreed to exchange volumes owned by the Company in the Midcontinent area and the Texas Gulf Coast area for equivalent volumes produced and owned by the limited partnership in the Big Piney area. The costs incurred, if any, to effect redeliveries pursuant to such exchange are borne by the Company.
The Company also has contracted to supply natural gas to a Texas City, Texas cogeneration facility which is owned by Cogenron Inc. Cogenron Inc. is 50% owned by Enron Corp. The primary contract provides for the sale of natural gas under a fixed schedule of prices substantially above current spot market prices. Current deliveries of approximately 45 MMcf of natural gas per day are being supplied primarily by purchases at market responsive prices under a long-term agreement with an Enron Corp. subsidiary. The Company has also entered into a price swap agreement with a third party that has the effect of converting the prices under this contract to a fixed schedule of prices. The resulting prices under this combination of purchase and price swap agreements are substantially below the fixed schedule of prices in the primary sales contract. The arrangements are designed, as to the volumes involved, to provide the Company a fixed margin of profit under its agreement with Cogenron Inc. However, the Company's commitment to deliver volumes of natural gas in excess of the current delivery levels at the schedule of predetermined prices discussed above could be disadvantageous to the Company during any time spot market prices exceed the applicable contract prices for natural gas.
WELLHEAD VOLUMES AND PRICES, AND LEASE AND WELL EXPENSES
The following table sets forth certain information regarding the Company's wellhead volumes of and average prices for natural gas per thousand cubic feet ('Mcf'), crude oil and condensate, and natural gas liquids per barrel ('Bbl'), and average lease and well expenses per thousand cubic feet equivalent ('Mcfe' - natural gas equivalents are determined using the ratio of 6.0 Mcf of natural gas to 1.0 barrel of crude oil and condensate or natural gas liquids) delivered during each of the three years in the period ended December 31, 1993:
YEAR ENDED DECEMBER 31, 1993 1992 1991
VOLUMES (PER DAY) Natural Gas (MMcf) United States---------------- 648.6(1) 533.6(1) 465.8 Canada----------------------- 58.4 30.0 24.8 Trinidad--------------------- 2.3 - - Total---------------------- 709.3(1) 563.6(1) 490.6 Crude Oil and Condensate (MBbl) United States---------------- 6.6 6.3 5.9 Canada----------------------- 2.2 2.2 2.3 Trinidad--------------------- .1 - - Total---------------------- 8.9 8.5 8.2 Natural Gas Liquids (MBbl) United States---------------- .2 .3 .3 Canada----------------------- .4 .4 .3 Trinidad--------------------- - - - Total---------------------- .6 .7 .6 AVERAGE PRICES Natural Gas ($/Mcf) United States---------------- $ 1.97(2) $ 1.61(2) $ 1.38 Canada----------------------- 1.34 1.18 1.32 Trinidad--------------------- .89 - - Composite------------------ 1.92(2) 1.58(2) 1.37 Crude Oil and Condensate ($/Bbl) United States---------------- $ 16.96 $ 18.29 $ 19.24 Canada----------------------- 14.63 16.80 17.58 Trinidad--------------------- 14.36 - - Composite------------------ 16.37 17.90 18.78 Natural Gas Liquids ($/Bbl) United States---------------- $ 13.85 $ 11.56 $ 10.79 Canada----------------------- 9.46 10.05 12.48 Trinidad--------------------- - - - Composite------------------ 11.12 10.69 11.64 LEASE AND WELL EXPENSES ($/MCFE) United States---------------- $ .18 $ .20 $ .23 Canada----------------------- .48 .50 .57 Trinidad--------------------- 1.46 - - Composite------------------ .21 .22 .25
(1) Includes 81.0 MMcf per day in 1993 and 27.6 MMcf per day in 1992 delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended.
(2) Includes an average equivalent wellhead value of $1.57 per Mcf in 1993 and $1.70 per Mcf in 1992 for the volumes described in note (1), net of transportation costs.
OTHER NATURAL GAS MARKETING VOLUMES AND PRICES
The following table sets forth certain information regarding the Company's volumes of natural gas delivered under other marketing and volumetric production payment arrangements, and resulting average of sales prices and per unit amortization of deferred revenues along with associated costs during each of the three years in the period ended December 31, 1993. (See 'Marketing' for a discussion of other natural gas marketing arrangements and agreements).
YEAR ENDED DECEMBER 31, 1993 1992 1991 Volumes (MMcf per day)--------------- 293.4(1) 254.9(1) 237.2 Average Gross Revenue ($/Mcf)-------- $ 2.57(2) $ 2.62(2) $ 2.63 Associated Costs ($/Mcf)(4)---------- 2.32(3) 1.99(3) 1.75 Margin ($/Mcf)----------------------- $ 0.25 $ 0.63 $ 0.88
(1) Includes 81.0 MMcf per day in 1993 and 27.6 MMcf per day in 1992 delivered under the terms of volumetric production payment and exchange agreements effective October 1, 1992, as amended.
(2) Includes per unit deferred revenue amortization for the volumes detailed in note (1) at an equivalent of $2.50 per Mcf ($2.40 per million British thermal units) in 1993 and $2.51 per Mcf ($2.40 per million British thermal units) in 1992.
(3) Includes an average value of $2.20 per Mcf in 1993 and $2.37 per Mcf in 1992, including average equivalent wellhead value, any applicable transportation costs and exchange differentials, for the volumes detailed in note (1).
(4) Including transportation and exchange differentials.
COMPETITION
The Company actively competes for reserve acquisitions and exploration leases, licenses and concessions, frequently against companies with substantially larger financial and other resources. To the extent the Company's exploration budget is lower than that of certain of its competitors, the Company may be disadvantaged in effectively competing for certain reserves, leases, licenses and concessions. Competitive factors include price, contract terms, and quality of service, including pipeline connection times and distribution efficiencies. In addition, the Company faces competition from other producers and suppliers, including competition from Canadian natural gas.
REGULATION
DOMESTIC REGULATION OF NATURAL GAS AND CRUDE OIL PRODUCTION. Natural gas and crude oil production operations are subject to various types of regulation, including regulation in the United States by state and federal agencies.
Domestic legislation affecting the oil and gas industry is under constant review for amendment or expansion. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations which, among other things, require permits for the drilling of wells, regulate the spacing of wells, prevent the waste of natural gas and crude oil resources through proration, require drilling bonds and regulate environmental and safety matters. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its profitability.
A substantial portion of the Company's oil and gas leases in the Big Piney area and in the Gulf of Mexico, as well as some in other areas, are granted by the federal government and administered by the Bureau of Land Management (the 'BLM') and the Minerals Management Service (the 'MMS') federal agencies. Operations conducted by the Company on federal oil and gas leases must comply with numerous statutory and regulatory restrictions. Certain operations must be conducted pursuant to appropriate permits issued by the BLM and the MMS.
Sales of crude oil, condensate and natural gas liquids by the Company are made at unregulated market prices.
The transportation and sale for resale of natural gas in interstate commerce are regulated pursuant to the Natural Gas Act of 1938 (the 'NGA') and the Natural Gas Policy Act of 1978 (the 'NGPA'). These statutes are administered by the Federal Energy Regulatory Commission (the 'FERC'). Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act of 1989 deregulated natural gas prices for all 'first sales' of natural gas, which includes all sales by the Company of its own production. Consequently, sales of the Company's natural gas currently may be made at market prices, subject to applicable contract provisions.
Regulation of natural gas importation is administered primarily by the Department of Energy's Office of Fossil Energy (the 'DOE/FE'), pursuant to the NGA. The NGA provides that any party seeking to import natural gas must first seek DOE/FE authorization, which authorization may be granted, modified or denied in accordance with the public interest. The Energy Policy Act of 1992 amended the NGA's public interest standard with respect to imports from and exports to certain countries, such as Canada, to deem imports from and exports to such countries to be in the public interest, and require such import/export applications to be granted without delay. In addition, the Energy Policy Act amended the NGPA to treat natural gas imported from Canada as 'first sales' of natural gas under Section 3 of the NGPA, thus allowing such imported natural gas to be sold for resale without certificate authorization from the FERC. Additionally, the National Energy Board of Canada has dramatically revised its natural gas export policies to permit large volumes of Canadian natural gas to compete with natural gas produced in the U.S. for the U.S. spot market. Additional natural gas pipeline capacity from Canada to the U.S. has been built and other such construction proposals are pending approval. While the impact on the Company of this change is uncertain, it is possible that it will increase competition in the markets in which the Company sells natural gas. For example, Canadian natural gas competes directly with natural gas produced from the Company's Big Piney area for customers located in the Pacific Northwest region of the United States.
Since 1985, the FERC has endeavored to make natural gas transportation more accessible to gas buyers and sellers on an open and non-discriminatory basis. These efforts have significantly altered the marketing and pricing of natural gas. The FERC's latest action in this area is Order No. 636, issued in April 1992, which mandates a fundamental restructuring of interstate pipeline sales and transportation services. Order No. 636 requires interstate natural gas pipelines to 'unbundle' or segregate the sales, transportation, storage, and other components of their existing city-gate sales service, and to separately state the rates for each unbundled service. Under Order No. 636, unbundled pipeline sales can be made only in the production areas. Order No. 636 also requires interstate pipelines to assign capacity rights they have on upstream pipelines to such pipelines' former sales customers and provides for the recovery by interstate pipelines of costs associated with the transition from providing bundled sales services to providing unbundled transportation and storage services. The purpose of Order No. 636 is to further enhance competition in the natural gas industry by assuring the comparability of pipeline sales service and services offered by a pipelines' competitors. Various aspects of Order No. 636 were challenged, including alleged shifts of costs between pipeline customer groups and the continuing reliability of unbundled services. In two subsequent orders on rehearing of Order No. 636, namely Order Nos. 636-A and 636-B, the FERC modified the original order in response to these and other concerns. As of early February 1994, the FERC had issued final orders accepting most pipelines' Order No. 636 compliance filings. Numerous parties have filed petitions for court review of Order Nos. 636, 636-A and 636-B, as well as orders in individual pipeline restructuring proceedings. Upon such judicial review, these orders may be reversed in whole or in part. Order No. 636 does not directly regulate the Company's activities, but has had and will have an indirect effect because of its broad scope. With Order No. 636 only partially implemented and subject to court review, it is difficult to predict with precision its effects. In many instances,
however, Order No. 636 has substantially reduced or brought to an end interstate pipelines' traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. Order No. 636 has also created substantial uncertainty with respect to the marketing and transportation of natural gas. In spite of this uncertainty, Order No. 636 may enhance the Company's ability to market and transport its natural gas production.
In December 1992, the FERC issued Order No. 547, governing the issuance of blanket marketer sales certificates to all natural gas sellers other than interstate pipelines. The order eliminates the need for natural gas producers and marketers to seek specific authorization under Section 7 of the NGA from the FERC to make sales of natural gas, such as imported natural gas and natural gas purchased from interstate pipelines. Instead, effective January 7, 1993, these natural gas sellers, by operation of the order, will be issued blanket certificates of public convenience and necessity allowing them to make jurisdictional natural gas sales for resale at negotiated rates without seeking specific FERC authorization. For marketers affiliated with interstate pipelines, Order No. 547 becomes effective for sales involving each affiliated pipeline as that pipeline complies with Order No. 636. The FERC intends Order No. 547, in tandem with Order No. 636, to foster a competitive market for natural gas by giving natural gas purchasers access to multiple supply sources at market-driven prices. The Company, as a natural gas producer, is covered by Order No. 547 and stands to benefit from the opportunity to market natural gas more freely under the blanket certificate as well as from the potential improvement in access to multiple natural gas purchasers.
In December 1993, the FERC issued Order No. 497-E, which modified in some respects the standards of conduct, record keeping and reporting requirements and other measures that govern relationships between interstate pipelines and their marketing affiliates. Order No. 497-E narrowed the contemporaneous disclosure standard of conduct and the reporting requirements, while at the same time possibly expanding the class of pipeline and marketing affiliate employees to whom the standards of conduct apply. Order No. 497-E also extended until June 1994 the sunset date of the reporting requirements. The FERC simultaneously issued a notice of proposed rulemaking to revise these reporting requirements, which would establish new rules to go into effect before the June 1994 sunset date. Order No. 497 does not directly regulate the Company's activities, although a substantial portion of the Company's natural gas production is sold to or transported by interstate pipeline affiliates which are subject to the Order. The Company's activities may therefore be indirectly affected by these regulations.
The Company owns, directly or indirectly, certain natural gas pipelines that it believes meet the traditional tests the FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction under the NGA. State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, non-discriminatory take requirements, but does not generally entail rate regulation. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels as the pipeline restructuring under Order No. 636 is implemented. For example, the State of Oklahoma recently enacted a prohibition against discriminatory gathering rates. In certain recent cases, the FERC has asserted ancillary NGA jurisdiction over gathering activities of interstate pipelines and their affiliates. In addition, the FERC recently convened a conference to consider issues relating to gathering services performed by interstate pipelines or their affiliates. The FERC intends to use information obtained to reevaluate the appropriateness of its traditional gathering criteria in light of Order No. 636 and to establish consistent policies for gathering rates and services for both interstate pipelines and their affiliates. It is not possible at this time to predict the outcome of this proceeding although it could ultimately affect access to and gathering rates for interstate gathering services. The Company's gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services.
The Company cannot predict the effect that any of the aforementioned orders or the challenges to such orders will ultimately have on the Company's operations. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC and the courts.
The Company cannot predict when or whether any such proposals or proceedings may become effective. It should also be noted that the natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less regulated approach currently being pursued by the FERC will continue indefinitely. Thus, the Company cannot predict the ultimate outcome or durability of the unbundled regulatory regime mandated by Order No. 636.
ENVIRONMENTAL REGULATION. Various federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect the Company's operations and costs as a result of their effect on natural gas and crude oil exploration, development and production operations. It is not anticipated that the Company will be required in the near future to expend amounts that are material in relation to its total exploration and development expenditure program by reason of environmental laws and regulations, but inasmuch as such laws and regulations are frequently changed, the Company is unable to predict the ultimate cost of compliance.
The Company has been named as a potentially responsible party in one Comprehensive Environmental Response Compensation and Liability Act proceeding. However, management does not believe that any potential assessment resulting from such proceeding will have a materially adverse effect on the financial condition or results of operations of the Company.
CANADIAN REGULATION. In Canada, the petroleum industry operates under Federal, provincial and municipal legislation and regulations governing land tenure, royalties, production rates, pricing, environmental protection, exports and other matters. The price of natural gas and crude oil in Canada has been deregulated and is now determined by market conditions and negotiations between buyers and sellers.
Various matters relating to the transportation and export of natural gas continue to be subject to regulation by both provincial and Federal agencies; however, the North American Free Trade Agreement has reduced the risk of altering cross-border commercial transactions.
Canadian governmental regulations may have a material effect on the economic parameters for engaging in oil and gas activities in Canada and may have a material effect on the advisability of investments in Canadian oil and gas drilling activities. The Company is monitoring political, regulatory and economic developments in Canada.
RELATIONSHIP BETWEEN THE COMPANY AND ENRON CORP.
OWNERSHIP OF COMMON STOCK. Enron Corp. owns 80% of the outstanding shares of common stock of the Company and, through its ability to elect all directors of the Company, has the ability to control all matters relating to the management of the Company, including any determination with respect to acquisition or disposition of Company assets, future issuance of common stock or other securities of the Company and any dividends payable on the common stock. Enron Corp. also has the ability to control the Company's exploration, development, acquisition and operating expenditure plans. If Enron Corp. should sell a substantial amount of the common stock of the Company that it owns, such action could adversely affect the prevailing market price for the common stock and could impair the Company's ability to raise capital through the sale of its equity securities. In addition, a sale by Enron Corp. of any common stock owned by Enron Corp. would cause Enron Corp.'s ownership interest in the Company to fall below 80% with the result that (i) the Company would cease to be included in the consolidated federal income tax return filed by Enron Corp. and (ii) the tax allocation agreement between the Company and Enron Corp. described below would terminate. The Company has granted certain registration rights to Enron Corp. with respect to the common stock owned by Enron Corp. (See 'Contractual Arrangements' below). There is no agreement between Enron Corp. and any other party, including the Company, that would prevent Enron Corp. from acquiring additional shares of common stock of the Company.
CONTRACTUAL ARRANGEMENTS. The Company entered into a Services Agreement (the 'Services Agreement') with Enron Corp. effective January 1989, pursuant to which Enron Corp. provided various services, such as maintenance of certain employee benefit plans, provision of telecommunications and computer services, lease of office space and the provision of purchasing and operating services and certain other corporate staff and support services. Such services historically have been supplied to the Company by Enron Corp., and the Services Agreement provided for the further delivery of such services substantially identical in nature and quality to those services previously provided. The Company agreed to a fixed rate for the rental of office space and to reimburse Enron Corp. for all other direct costs incurred in rendering services to the Company under the contract and to pay Enron Corp. for allocated indirect costs incurred in rendering such services up to an annual maximum of $8 million, such cap to be increased for inflation and certain changes in the Company's allocation bases with the increase limited to a maximum of 10% per year. The Services Agreement was for an initial term of five years through December 1993. Effective January 1, 1994, the Company and Enron Corp. entered into a new services agreement (the 'New Services Agreement') pursuant to which Enron Corp. will, among other things, provide for the Company similar services substantially identical in nature and quality to those provided under terms of the previous agreement. The Company has agreed to pay and to reimburse Enron Corp. on bases essentially consistent with those included in the previous agreement, except that allocated indirect costs are subject to an annual maximum of $6.7 million for the year 1994 with any increase in such maximum for subsequent years not to exceed 7.5% per year. The New Services Agreement is for an initial term of five years through December 1998 and will continue thereafter until terminated by either party.
The Company is included in the consolidated federal income tax return filed by Enron Corp. as the common parent for itself and its subsidiaries and affiliated companies, excluding any foreign subsidiaries. Consistent therewith and pursuant to a Tax Allocation Agreement (the 'Tax Agreement') between the Company, the Company's subsidiaries and Enron Corp., either Enron Corp. will pay to the Company and each subsidiary an amount equal to the tax benefit realized in the Enron Corp. consolidated federal income tax return resulting from the utilization of the Company's or the subsidiary's net operating losses and/or tax credits, or the Company and each subsidiary will pay to Enron Corp. an amount equal to the federal income tax computed on its separate taxable income less the tax benefits associated with any net operating losses and/or tax credits generated by the Company or the subsidiary which are utilized in the Enron Corp. consolidated return. Enron Corp. will pay the Company and each subsidiary for the tax benefits associated with their net operating losses and tax credits utilized in the Enron Corp. consolidated return, provided that a tax benefit was realized except as discussed in the following paragraph, even if such benefits could not have been used by the Company or the subsidiary on a separately filed tax return.
In 1991, the Company and Enron Corp. modified the Tax Agreement to provide that, through 1992, the Company will realize the benefit of certain tight gas sand federal income tax credits available to the Company on a stand alone basis. The Company has also entered into an agreement with Enron Corp. providing for the Company to be paid for all realizable benefits associated with tight gas sand federal income tax credits concurrent with tax reporting and settlement for the periods in which they are generated. (See 'Other Matters Tight Gas Sand Tax Credits (Section 29) and Severance Tax Exemption').
The Tax Agreement applies to the Company and each of its subsidiaries for all years in which the Company or any of its subsidiaries are or were included in the Enron Corp. consolidated return.
To the extent a state or other taxing jurisdiction requires or permits a consolidated, combined, or unitary tax return to be filed and such return includes the Company or any of its subsidiaries, the principles expressed with respect to consolidated federal income tax allocation shall apply.
Pursuant to the terms of a Stock Restriction and Registration Agreement with Enron Corp., the Company has agreed that upon the request of Enron Corp. (or certain assignees), the Company will register under the Securities Act of 1933 and applicable state securities laws the sale of the Company
common stock owned by Enron Corp. which Enron Corp. has requested to be registered. The Company's obligation is subject to certain limitations relating to a minimum amount of common stock required for registration, the timing of registration and other similar matters. The Company is obligated to pay all expenses incidental to such registration, excluding underwriters' discounts and commissions and certain legal fees and expenses.
CONFLICTS OF INTEREST. The nature of the respective businesses of the Company and Enron Corp. and its affiliates is such as to potentially give rise to conflicts of interest between the two companies. Conflicts could arise, for example, with respect to transactions involving purchases, sales and transportation of natural gas and other business dealings between the Company and Enron Corp. and its affiliates, potential acquisitions of businesses or oil and gas properties, the issuance of additional shares of voting securities, the election of directors or the payment of dividends by the Company.
Enron Corp. has advised the Company that it does not currently intend to engage in the exploration for and/or development and production of natural gas and crude oil except through its ownership of common stock of the Company. However, circumstances may arise that would cause Enron Corp. to engage in the exploration for and/or development and production of natural gas and crude oil in competition with the Company. For example, opportunities might arise which would require financial resources greater than those available to the Company or which are located in areas or countries in which the Company does not intend to operate. Also, Enron Corp. might acquire a competing oil and gas business as part of a larger acquisition. In addition, as part of Enron Corp.'s strategy of securing supplies of natural gas, Enron Corp. may from time to time acquire producing properties, and thereafter engage in exploration, development and production activities with respect to such properties. Such acquisition, exploration, development and production activities may directly or indirectly compete with the Company's business. Thus, there can be no assurances that Enron Corp. will not engage in the natural gas and crude oil exploration, development and production business in competition with the Company.
The Company and Enron Corp. and its affiliates have in the past entered into significant intercompany transactions and agreements incident to their respective businesses, and the Company and Enron Corp. and its affiliates may be expected to enter into material transactions and agreements from time to time in the future. Such transactions and agreements have related to, among other things, the purchase and sale of natural gas, the financing of exploration and development efforts by the Company, and the provision of certain corporate services. (See 'Marketing' and the Consolidated Financial Statements and notes thereto). The Company believes that its existing transactions and agreements with Enron Corp. and its affiliates have been at least as favorable to the Company as could be obtained from third parties, and the Company intends that the terms of any future transactions and agreements between the Company and Enron Corp. and its affiliates will be at least as favorable to the Company as could be obtained from third parties.
OTHER MATTERS
ENERGY PRICES. Since the Company is primarily a natural gas company, it is more significantly impacted by changes in natural gas prices than in the prices for crude oil, condensate and natural gas liquids. During recent periods, natural gas has been priced significantly below parity with crude oil, condensate and natural gas liquids based on the energy equivalency of, and differences in transportation and processing costs associated with, the respective products. This imbalance in parity has been primarily driven by, among other things, a supply of domestic natural gas volumes in excess of demand requirements. The Company is unable to predict when this supply imbalance may resolve due to the significant impacts of factors such as general economic conditions, weather and other international energy supplies over which the Company has no control. However, during the latter part of 1993, certain shifts in the pricing structure for natural gas and crude oil and condensate suggest that the significance of the lack of parity between natural gas and crude oil and condensate pricing may be beginning to lessen.
Natural gas prices have fluctuated, at times rather dramatically, during the last three years. These fluctuations have resulted in an overall increase in average wellhead natural gas prices realized by the Company of 15% from 1991 to 1992 and 22% from 1992 to 1993. Due to the many uncertainties associated with the world political environment, the availabilities of other world wide energy supplies and the relative competitive relationships of the various energy sources in the view of the consumers, the Company is unable to predict what changes may occur in natural gas prices in the future.
Crude oil and condensate prices also have fluctuated, at times rather dramatically, during the last three years. These fluctuations have resulted in an overall decline in average wellhead crude and condensate prices realized by the Company of 5% from 1991 to 1992 and 9% from 1992 to 1993. Due to the many uncertainties associated with the world political environment, the availabilities of other world wide energy supplies and the relative competitive relationships of the various energy sources in the view of the consumers, the Company is unable to predict what changes may occur in crude oil and condensate prices in the future.
TIGHT GAS SAND TAX CREDITS (SECTION 29) AND SEVERANCE TAX EXEMPTION. 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 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 $43 per barrel in current dollars. Significant benefits from the tax credit are accruing to the Company since a portion (and in some cases a substantial portion) of the Company's natural gas production from new wells drilled after November 5, 1990, and before January 1, 1993, on the Company's leases in several of the Company's significant producing areas qualify for this tax credit.
Certain 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 Texas severance taxes, subject to certain limitations.
OTHER. All of the Company's oil and gas activities are subject to the risks normally incident to the exploration for and development and production of natural gas and crude oil, including blowouts, cratering and fires, each of which could result in damage to life and property. Offshore operations are subject to usual marine perils, including hurricanes and other adverse weather conditions, and governmental regulations as well as interruption or termination by governmental authorities based on environmental and other considerations. In accordance with customary industry practices, insurance is maintained by the Company against some, but not all, of the risks. Losses and liabilities arising from such events could reduce revenues and increase costs to the Company to the extent not covered by insurance.
The Company's overseas operations are subject to certain risks, including expropriation of assets, risks of increases in taxes and government royalties, renegotiation of contracts with foreign governments, political instability, payment delays, limits on allowable levels of production and current exchange and repatriation losses, as well as changes in laws and policies governing operations of overseas-based companies generally.
CURRENT EXECUTIVE OFFICERS OF THE REGISTRANT
The current executive officers of the Company and their names and ages are as follows:
NAME AGE POSITION Forrest E. Hoglund----------------- 60 Chairman of the Board, President and Chief Executive Officer; Director Joe Michael McKinney--------------- 54 President-International Operations Mark G. Papa----------------------- 47 President-North American Operations George E. Uthlaut------------------ 60 Senior Vice President-Operations Walter C. Wilson------------------- 51 Senior Vice President and Chief Financial Officer Ben B. Boyd------------------------ 52 Vice President and Controller Dennis M. Ulak--------------------- 40 Vice President and General Counsel
Forrest E. Hoglund joined the Company as Chairman of the Board, Chief Executive Officer and Director in September 1987. Since May 1990, he has also served as President of the Company. Mr. Hoglund was a director of USX Corporation from February 1986 until September 1987. He joined Texas Oil & Gas Corp. ('TXO') in 1977 as president, was named Chief Operating Officer in 1979, Chief Executive Officer in 1982, and served TXO in those capacities until September 1987. Mr. Hoglund is also a director of Texas Commerce Bancshares, Inc.
Joe Michael McKinney has been President-International Operations since February 1994 with responsibilities for all exploration, drilling, production and engineering activities for the Company's international ventures outside North America. Mr. McKinney joined Enron Exploration Company, a wholly-owned subsidiary of the Company, in December 1991 as Senior Vice President of Operations and was elected President and Chief Operating Officer of Enron Exploration Company in April 1993, a capacity in which he continues to serve. Prior to joining the Company, Mr. McKinney held operations management positions with Union Texas Petroleum Company, The Superior Oil Company and Exxon Company, USA.
Mark G. Papa has been President-North American Operations since February 1994. From May 1986 through January 1994, Mr. Papa served as Senior Vice President-Operations. Mr. Papa joined Belco Petroleum Corporation, a predecessor of the Company, in 1981 as Division Production Coordinator and served as Senior Vice President-Drilling and Production, BelNorth Petroleum Corporation from May 1984 until May 1986.
George E. Uthlaut has been Senior Vice President-Operations of the Company since November 1987. Mr. Uthlaut was previously employed by Exxon Corporation (and affiliates) for 29 years in a number of managerial and technical positions. His last position was Headquarters Operations Manager, Production Department, Exxon Company, USA.
Walter C. Wilson has been Senior Vice President and Chief Financial Officer since May 1991. Mr. Wilson joined the Company in November 1987 as Vice President and Controller and was named Senior Vice President-Finance in October 1988. Prior to joining the Company Mr. Wilson held financial management positions with Exxon Company, USA for 16 years and The Superior Oil Company for 4 years.
Ben B. Boyd has been Vice President and Controller since March 1991. Mr. Boyd joined the Company in March 1989 as Director of Accounting and was named Controller in May 1990. Prior to joining the Company, Mr. Boyd held financial management positions with DeNovo Oil & Gas, Inc., Scurlock Oil Company and Coopers & Lybrand.
Dennis M. Ulak has been Vice President and General Counsel since March 1992. Mr. Ulak joined the Company in March 1987 as Senior Counsel and was named Assistant General Counsel in
August 1990. Prior to joining the Company, Mr. Ulak held various legal positions with Enron Corp. and Northern Natural Gas Company.
ITEM 2.



ITEM 2. PROPERTIES
OIL AND GAS EXPLORATION AND PRODUCTION PROPERTIES AND RESERVES
RESERVE INFORMATION. For estimates of the Company's net proved and proved developed reserves of natural gas and liquids, including crude oil, condensate and natural gas liquids, see 'Supplemental Information to Consolidated Financial Statements.'
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth in Supplemental Information to Consolidated Financial Statements represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and liquids, including crude oil, condensate and natural gas liquids, that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the amount and quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers normally vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based.
In general, the volume of production from oil and gas properties owned by the Company declines as reserves are depleted. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration and development activities, or both, the proved reserves of the Company will decline as reserves are produced. Volumes generated from future activities of the Company are therefore highly dependent upon the level of success in acquiring or finding additional reserves and the costs incurred in doing so.
The Company's estimates of reserves filed with other federal agencies agree with the information set forth in Supplemental Information to Consolidated Financial Statements.
ACREAGE. The following table summarizes the Company's developed and undeveloped acreage at December 31, 1993. Excluded is acreage in which the Company's interest is limited to owned royalty, overriding royalty and other similar interests.
PRODUCING WELL SUMMARY. The following table reflects the Company's ownership in gas wells in 316 fields and oil wells in 75 fields located in Texas, offshore Texas and Louisiana in the Gulf of Mexico, Oklahoma, New Mexico, Utah, Wyoming, California and various other states, Canada and Trinidad at December 31, 1993. Gross oil and gas wells include 229 with multiple completions.
PRODUCTIVE WELLS GROSS NET Gas---------------------------------- 4,674 3,170 Oil---------------------------------- 884 527 Total---------------------------- 5,558 3,697
DRILLING AND ACQUISITION ACTIVITIES. During the years ended December 31, 1993, 1992 and 1991 the Company spent approximately $430.1, $395.7 and $254.8 million, respectively, for exploratory and development drilling and acquisition of leases and producing properties. The Company drilled, participated in the drilling of or acquired wells as set out in the table below for the periods indicated:
All of the Company's drilling activities are conducted on a contract basis with independent drilling contractors. The Company owns no drilling equipment.
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS
The Company and its subsidiaries and related companies are named defendants in numerous lawsuits and named parties in numerous governmental proceedings arising in the ordinary course of business. While the outcome of lawsuits or other proceedings against the Company cannot be predicted with certainty, management does not expect these matters to have a material adverse effect on the financial condition or results of operations of the Company. TransAmerican Natural Gas Corporation ('TransAmerican') has filed a petition against the Company and Enron Corp. alleging breach of contract, tortious interference with contract, misappropriation of trade secrets and violation of state antitrust laws. The petition, as amended, seeks actual damages of $100 million plus exemplary damages of $300 million. The Company has answered the petition and is actively defending the matter; in addition, the Company has filed counterclaims against TransAmerican and a third-party claim against its sole shareholder, John R. Stanley, alleging fraud, negligent misrepresentation and breach of state antitrust laws. Trial, originally set for February 7, 1994, is now set for September 12, 1994. Although no assurances can be given, the Company believes that the claims made by TransAmerican are totally without merit, that the ultimate resolution of the matter will not have a materially adverse effect on its financial condition or results of operations, and that such ultimate resolution could result in a recovery to the Company.
ITEM 4.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the fourth quarter of 1993.
PART II
ITEM 5.

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS
The following table sets forth, for the periods indicated, the high and low sale prices per share for the 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 First Quarter-------------------- 22.25 16.25 .05 Second Quarter------------------- 21.50 18.00 .05 Third Quarter-------------------- 24.63 17.63 .05 Fourth Quarter------------------- 25.13 19.25 .05 First Quarter-------------------- 21.88 16.63 .05 Second Quarter------------------- 27.25 20.50 .05 Third Quarter-------------------- 35.88 25.38 .05 Fourth Quarter------------------- 34.38 27.50 .05 First Quarter-------------------- 40.63 26.75 .06 Second Quarter------------------- 45.00 35.75 .06 Third Quarter-------------------- 53.63 39.75 .06 Fourth Quarter------------------- 54.00 34.13 .06
As of March 1, 1994, there were approximately 500 record holders of the Company's common stock, including individual participants in security position listings. There are an estimated 5,600 beneficial owners of the Company's common stock, including shares held in street name.
Following the initial public offering and sale of its common stock in October 1989, the Company paid quarterly dividends of $0.05 per share beginning with an initial dividend paid in January 1990 with respect to the fourth quarter of 1989. Beginning in January 1993 with respect to the fourth quarter of 1992, the Company has paid quarterly dividends of $0.06 per share. The Company currently intends to continue to pay quarterly cash dividends on its outstanding shares of common stock. However, the determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, the financial condition, funds from operations, level of exploration and development expenditure opportunities and future business prospects of the Company.
ITEM 6.

ITEM 6. SELECTED FINANCIAL DATA
ITEM 7.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following review of operations for each of the three years in the period ended December 31, 1993 should be read in conjunction with the consolidated financial statements of the Company and notes thereto beginning with page.
RESULTS OF OPERATIONS
NET OPERATING REVENUES. Volume and price statistics for the specified years were as follows:
YEAR ENDED DECEMBER 31, 1993 1992 1991 Wellhead Volumes Natural Gas (MMcf per day)------- 709.3(1) 563.6(1) 490.6 Crude Oil and Condensate (MBbl per day)----------------------- 8.9 8.5 8.2 Natural Gas Liquids (MBbl per day)--------------------------- 0.6 0.7 0.6 Wellhead Average Prices Natural Gas ($/Mcf)-------------- $ 1.92(2) $ 1.58(2) $ 1.37 Crude Oil and Condensate ($/Bbl)------------------------ 16.37 17.90 18.78 Natural Gas Liquids ($/Bbl)------ 11.12 10.69 11.64 Other Natural Gas Marketing Volumes (MMcf per day)----------- 293.4(1) 254.9(1) 237.2 Average Gross Revenue ($/Mcf)---- $ 2.57(3) $ 2.62(3) $ 2.63 Associated Costs ($/Mcf) (5)----- 2.32(4) 1.99(4) 1.75 Margin ($/Mcf)------------------- $ 0.25 $ 0.63 $ 0.88
(1) Includes 81.0 MMcf per day in 1993 and 27.6 MMcf per day in 1992 delivered under the terms of volumetric production payment and exchange agreements effective October 1, 1992, as amended.
(2) Includes an average equivalent wellhead value of $1.57 per Mcf in 1993 and $1.70 per Mcf in 1992 for the volumes detailed in note (1), net of transportation costs.
(3) Includes per unit deferred revenue amortization for the volumes detailed in note (1) at an equivalent of $2.50 per Mcf ($2.40 per million British thermal units) in 1993 and $2.51 per Mcf ($2.40 per million British thermal units) in 1992.
(4) Includes an average value of $2.20 per Mcf in 1993 and $2.37 per Mcf in 1992, including average equivalent wellhead value, any applicable transportation costs and exchange differentials, for the volumes detailed in note (1).
(5) Including transportation and exchange differentials.
During 1993, net operating revenues increased to $568 million, up $115 million as compared to 1992.
Average wellhead natural gas volumes increased approximately 26% compared to 1992 primarily reflecting the effects of exploration and development activities relating to tight gas sand formations. Wellhead natural gas delivered volumes were curtailed less during portions of 1993 than for the comparable periods in 1992 due to the significant increases realized in wellhead natural gas prices in 1993. Average wellhead natural gas prices were up approximately 22% in 1993 over those received in 1992, adding approximately $87 million to net operating revenues. Increases in wellhead natural gas volumes in 1993 added $83 million to net operating revenues compared to 1992. Average wellhead crude oil and condensate prices in 1993 were down 9% compared to 1992, reducing net operating revenues by $5 million. Increases in wellhead crude oil and condensate volumes in 1993 added approximately $2 million to net operating revenues compared to 1992.
Other marketing activities associated with sales and purchases of natural gas, natural gas price swap transactions, other commodity price hedging of natural gas and crude oil and condensate prices utilizing futures market transactions, and margins relating to the volumetric production payment added $8 million to net operating revenues during 1993. This decrease of $54 million from 1992 primarily results from shrinking margins associated with sales under long-term fixed price contracts and amortization of volumetric production payment deferred revenue due to increases in market responsive natural gas prices associated with volumes supplying these dispositions and losses on natural gas commodity price hedging activities utilizing NYMEX commodity market transactions. The average associated costs of natural gas marketing, price swap and volumetric production payment transactions, including, where appropriate, average wellhead value, transportation costs and exchange differentials, increased $.33 per Mcf. Related other natural gas marketing volumes increased 15%.
The net reduction in benefits from these other marketing activities, a substantial portion of which serve as hedges of commodity price risks for a portion of wellhead deliveries, are more than offset by an increase in revenues associated with market responsive price increases for wellhead deliveries, as noted above. The $18 million hedging loss in 1993 associated with forward sales of natural gas using the NYMEX futures market reflects the effects of transactions sold over a period of time that turned out to be a continually increasing natural gas pricing period. If the stronger market responsive pricing environment continues, the incremental benefits realized by the Company in prior years from these other marketing activities will continue to be reduced. However, in such circumstances the Company will continue to realize more significant benefits from the improved pricing related to wellhead deliveries. (See Note 2 to Consolidated Financial Statements).
During 1992, net operating revenues increased to $453 million, up $65 million as compared to 1991.
Average wellhead natural gas volumes increased approximately 15% compared to 1991 primarily reflecting the effects of exploration and development activities relating to tight gas sand formations. Although exploration and development efforts resulted in deliverability increases in certain core areas, the potential earnings and cash flow benefits were mitigated by voluntary curtailments during 1992. Wellhead natural gas delivered volumes were voluntarily curtailed by as much as 25% of deliverability during portions of the year due to lower than acceptable prices. Average wellhead natural gas prices were up approximately 15% and average wellhead crude oil and condensate prices were down 5% compared to 1991. The increase in average wellhead natural gas price received by the Company increased net operating revenues by approximately $38 million. The increase in wellhead natural gas volumes added approximately $43 million to net operating revenues. Increases in wellhead crude oil and condensate delivered volumes added $2 million to net operating revenues. A decrease in the average wellhead crude oil and condensate price decreased net operating revenues by $3 million.
Other marketing activities associated with sales and purchases of natural gas, natural gas price swap transactions, natural gas and crude oil commodity price hedging utilizing futures market transactions and margins relating to the volumetric production payment added $63 million to net operating revenues during 1992, a decrease of $17 million from 1991. Other natural gas marketing volumes increased 7%. The average associated costs of supplying these commitments, including average equivalent wellhead value, transportation costs and exchange differentials, increased $.24 per Mcf.
OPERATING EXPENSES. During 1993, total operating expenses of $465 million were $112 million higher than the $353 million incurred in 1992. Lease and well expenses increased approximately $10 million primarily due to expanded domestic and international operations. Exploration expenses increased approximately $4 million primarily due to increased exploration activities in North America. Dry hole expenses increased by almost $8 million and lease impairments were $5 million higher than in 1992. An unsuccessful domestic deep well added nearly $4 million to dry hole expenses and a related $3 million to lease impairments in 1993. Dry hole expenses also reflect the impact of increased drilling activity outside North America. Depreciation, depletion and amortization ('DD&A') expense increased $70 million to $250 million reflecting an increase in production volumes and an average DD&A rate increase from $.79 per Mcfe in 1992 to $.89 per Mcfe for 1993. The DD&A rate increase is primarily due, as expected, to factors associated with the tight gas sands drilling program which costs are being more than offset by benefits realized in the form of tight gas sand federal income tax credits and certain state severance tax exemptions. General and administrative expenses increased almost $9 million to $45 million primarily reflecting cost reductions included in 1992 related to changes associated with certain employee compensation plans and overall higher costs in 1993 due to an expansion of domestic and international operations. Taxes other than income increased $7 million primarily due to increased production volumes and revenues in 1993, partially offset by continuing benefits associated with certain state severance tax exemptions allowed on high cost natural gas sales and a $3 million reduction of state franchise taxes resulting from refunds of prior year payments received in 1993.
Total per unit operating costs for lease and well expense, DD&A, general and administrative expense, interest expense, and taxes other than income increased $.03 per Mcfe, averaging $1.43 per Mcfe during 1993 compared to $1.40 per Mcfe for 1992. The total increase was associated with DD&A expense which was up $.10 per Mcfe as noted above being partially offset by a reduction of $.07 Mcfe in all other costs.
During 1992, operating expenses increased $29 million to $353 million as compared to 1991. However, cost per Mcfe, including those associated with exploration expenditures, declined $.08 to $1.56 per Mcfe in 1992. Lease and well expenses remained essentially flat compared to 1991. However, lease and well expense per Mcfe declined $.03 per Mcfe to $.22 per Mcfe in 1992. Per unit operating cost reductions reflect the effects of a continuing focus on controlling operating costs in all areas of Company operations and benefits realized from the sale of properties which required higher maintenance costs along with increasing volumes which tend to reduce per unit impacts of costs that are more fixed in nature. Exploration expenses of $33 million increased $2 million over 1991 due to certain exploration activities in new international areas of interest. Dry hole expenses of $11 million decreased $4 million from 1991 due to decreased drilling activity in areas outside of North America partially mitigated by increased domestic drilling activities. Impairment of unproved oil and gas properties increased approximately $2 million to $15 million primarily reflecting certain costs associated with the decision to discontinue exploration activities in certain areas outside of North America, including Egypt, Indonesia and Syria in addition to reflecting the effects of accelerated relinquishments of certain domestic acreage holdings. DD&A expense increased $19 million to $180 million primarily reflecting increased production mitigated by a decline in the average DD&A rate from $.81 per Mcfe in 1991 to $.79 per Mcfe in 1992. The reduction in DD&A rates per Mcfe reflects the effects of a continuing focus on adding reserves with low finding costs along with the benefits of selling certain properties with higher than average cost bases. General and administrative
expenses increased $1 million to $37 million primarily reflecting the effects of expanded operations. Taxes other than income increased $10 million to $28 million due to increased production volumes and revenues in 1992, increases in certain ad valorem and state franchise taxes and earnings benefits associated with the refund of certain state natural gas severance taxes in 1991 resulting from overpayments in prior years. This increase was mitigated by Texas severance tax exemptions for certain high cost gas production during 1992.
OTHER INCOME. Other income for 1993 of $20 million reflects an increase of $17 million from the $3 million recorded for 1992. Other income for 1993 includes $13 million in gains on sales of oil and gas properties, an increase of $7 million over 1992, $4 million in interest income associated with the investment of funds temporarily surplus to the Company (See Note 3 to Consolidated Financial Statements) and $4 million associated with settlements related to the termination of certain long-term natural gas contracts.
Other income in 1992 was $3 million compared to $12 million in 1991. Other income in 1992 included $6 million in gains on sales of oil and gas properties compared to $15 million in 1991.
INTEREST EXPENSE. Net interest expense decreased $12 million, or 55%, to $10 million in 1993 as compared to 1992 reflecting the repayment of a substantial portion of the Company's long-term debt in 1992 with proceeds from the sale of common stock in August 1992 and the sale of a volumetric production payment in September 1992. The estimated fair value of outstanding interest rate swap agreements at December 31, 1993 was a negative $3.3 million based upon termination values obtained from third parties. (See Note 12 to Consolidated Financial Statements).
Net interest expense decreased $7 million, or 24%, to $22 million in 1992 as compared to 1991, reflecting a restructuring of debt in early 1991 and lower interest rates. Using interest rate swap agreements with third parties effective in January 1992, the Company fixed short-term borrowing costs for the year for the equivalent of $225 million of its floating rate obligations. In addition, two of the interest rate swap agreements in notional amounts totalling $75 million were for a two-year period extending through 1993. Effective January 1, 1993, Enron Corp. assumed the Company's remaining obligations under these swap agreements.
INCOME TAXES. Income tax benefit in 1993 includes a benefit of approximately $65 million associated with tight gas sand federal income tax credit utilization, an approximate $7 million predominantly one-time non-cash charge recorded in the third quarter of 1993 primarily to adjust the Company's accumulated deferred federal income tax liability for the increase in the corporate federal income tax rate from 34% to 35% and a $12 million benefit from the reduction of the Company's accumulated deferred federal income tax liability resulting from a year end reevaluation of deferred tax liability requirements.
The Company adopted SFAS No. 109 effective January 1, 1993 and applied the provisions of the statement retroactively. As a result, the previously reported income tax benefit and net income for 1991 were restated with a reduction to both of $7 million. Net income for 1992 and 1993 was not affected by the restatement. The Company's consolidated balance sheets at December 31, 1992 and 1991 were also restated to reflect the increase to deferred income taxes payable of $7 million and the corresponding decrease to retained earnings of an equal amount.
Income tax benefit in 1992 includes a benefit of approximately $43 million associated with tight gas sand federal income tax credit utilization and $2.8 million primarily related to investment tax credit, tight gas sand federal income tax credit and percentage depletion utilization based on actual returns as filed and settlements on audit of tax returns of predecessor companies for the years 1984 through 1985.
Income tax benefit in 1991 includes a benefit of approximately $17 million associated with tight gas sand federal income tax credit utilization and $10.5 million related to utilization of net operating loss carryforwards, foreign tax credit and settlements on audit of tax returns of predecessor companies for tax years 1980 through 1983.
CAPITAL RESOURCES AND LIQUIDITY
CASH FLOW. The primary sources of cash for the Company during the three-year period ended December 31, 1993 included funds generated from operations, the sale of common stock, the sale of a volumetric production payment and proceeds from the sale of certain oil and gas properties. Primary cash outflows included funds used in operations, exploration and development expenditures, dividends, and the repayment of debt.
Discretionary cash flow, a frequently used measure of performance for exploration and production companies, is generally derived by adjusting net income to eliminate the effects of depreciation, depletion and amortization, impairment of unproved oil and gas properties, deferred taxes, property sales net of tax, certain other miscellaneous non-cash amounts, except for amortization of deferred revenue, and exploration and dry hole expenses. In the case of the Company, the elimination of revenues associated with the amortization of deferred revenues created by the sale by the Company of a volumetric production payment is reflected in investing cash flows. The Company generated discretionary cash flow of approximately $487 million in 1993, $320 million in 1992 and $252 million in 1991. The 1993 amount includes $50 million associated with a federal income tax refund resulting from the settlement of an audit of federal income taxes paid in prior years.
Net operating cash flows were approximately $480 million in 1993, $306 million in 1992 and $242 million in 1991. Increased 1993 net operating cash flows were primarily due to increased net operating revenues and a decrease in provision for current taxes resulting from both increased tight gas sand federal income tax credit utilization and proceeds from the receipt of a refund on settlement of an audit of federal income taxes paid in prior years. Increased 1992 net operating cash flows were primarily due to increased net operating revenues and an increase in current tax benefits as a result of tight gas sand federal income tax credit utilization.
SALE OF CERTAIN PROPERTIES. In 1993, the Company received proceeds of $42 million from the sale of certain producing and non-producing oil and gas properties. Taxable gains resulting from these sales generated federal income taxes of $8 million, leaving net proceeds of $34 million. During 1992, the Company received proceeds of $33 million from the sale of certain producing and non-producing oil and gas properties. Taxable gains resulting from these sales generated federal income taxes of $8 million, leaving net proceeds of $25 million. In 1991, the Company received proceeds of $23 million from the sale of certain producing and non-producing oil and gas properties. Taxable gains resulting from these sales generated income taxes of $5 million, leaving net proceeds of $18 million.
SALE OF COMMON STOCK. In August 1992, the Company completed the sale of 4.1 million shares of common stock resulting in aggregate net proceeds to the Company of approximately $112 million used primarily to repay long-term debt. Enron Corp. retained ownership of 80% of the Company.
SALE OF VOLUMETRIC PRODUCTION PAYMENT. In September 1992, the Company sold a volumetric production payment for $326.8 million to a limited partnership. (See 'Business - Marketing - Other Marketing' and Note 4 to Consolidated Financial Statements). Under the terms of the production payment agreements, the Company conveyed a real property interest in approximately 124 bcfe (136 trillion British thermal units) of natural gas and other hydrocarbons in the Big Piney area of Wyoming to the purchaser. Effective October 1, 1993, the agreements were amended providing for the extension of the original term of the volumetric production payment through March 31, 1999 and including a revised schedule of daily quantities of hydrocarbons to be delivered which is approximately one-half of the original schedule. The revised schedule will total approximately 89.1 Bcfe (97.8 trillion British thermal units) versus approximately 87.9 Bcfe (96.4 trillion British thermal units) remaining to be delivered under the original agreement. Daily quantities of hydrocarbons no longer required to be delivered under the revised schedule during the period from October 1, 1993 through June 30, 1996 are available for sale by the Company. The Company retains responsibility for its working interest share of the cost of operations. A portion of the proceeds of the sale was used to repay a portion of the Company's long-term debt, with surplus funds advanced to Enron Corp. under a promissory note which facilitates the deposit of funds temporarily surplus to the Company. In
accordance with generally accepted accounting principles, the Company accounted for the proceeds received in the transaction as deferred revenue which is being amortized into revenue and income as natural gas and other hydrocarbons are produced and delivered to the purchaser during the term, as revised, of the volumetric production payment thereby matching those revenues with the depreciation of asset values which remained on the balance sheet following the sale and the operating expenses incurred for which the Company retained responsibility. The Company expects the above transaction, as amended, to have minimal impact on future earnings. However, cash made available by the sale of the volumetric production payment has provided considerable financial flexibility for the pursuit of investment alternatives.
EXPLORATION AND DEVELOPMENT EXPENDITURES. The table below sets out components of actual exploration and development expenditures for the years ended December 31, 1993, 1992 and 1991, along with those budgeted for the year 1994.
ACTUAL BUDGETED EXPENDITURE CATEGORY 1993 1992 1991 1994 (IN MILLIONS) Capital Drilling and Facilities--------- $ 331.0 $ 259.9 $ 149.3 $ 360.0 Leasehold Acquisitions---------- 29.1 23.0 12.6 20.0 Producing Property Acquisitions-------------------- 9.2 65.2 42.4 4.0 Capitalized Interest and Other------------------------- 13.7 14.3 7.4 10.0 Total----------------------- 383.0 362.4 211.7 394.0 Exploration Expenses---------------- 55.3 44.0 46.1 56.0 Total------------------------------- $ 438.3 $ 406.4 $ 257.8 $ 450.0
Exploration and development expenditures in 1993 increased to $438 million, an 8% increase, as compared to the $406 million expended in 1992. The increase was attributable to increased domestic drilling activity with reduced emphasis on development drilling expenditures associated with tight gas sand formations. The Company also implemented its first development program outside of North America. During 1992 and 1993, the Company had a platform set, production facilities in place and natural gas flowing from the Kiskadee field offshore the southeast coast of Trinidad.
Exploration and development expenditures increased $149 million, or 58%, in 1992 compared to 1991. The increase was primarily attributable to increased development drilling expenditures associated with tight gas sand activities and the acquisition in December 1992 of approximately $40 million of producing properties in Canada. (See 'Business - Exploration and Production' for additional information detailing the specific geographic locations of the Company's drilling programs and 'Outlook' below for a discussion related to 1994 exploration and development expenditure plans).
FINANCING. The Company's long-term debt-to-total-capital ratio was 14% and 15% as of December 31, 1993 and 1992, respectively. The Company has entered into an agreement with Enron Corp. pursuant to which the Company may borrow funds from Enron Corp. at a representative market rate of interest on a revolving basis. During 1993, there were no funds borrowed by the Company under this agreement. Under a promissory note effective January 1, 1993 at a fixed interest rate of 7%, the Company advances funds temporarily surplus to the Company to Enron Corp. for investment purposes. Daily outstanding balances of funds advanced to Enron Corp. under the note averaged $60 million during 1993 with a balance of $97 million outstanding at December 31, 1993. There were no balances outstanding at December 31, 1993 under a commercial paper program initiated in 1990. The proceeds from the commercial paper program outstanding from time to time are used to fund current transactions. During 1993, total long-term debt increased $3 million to $153 million as a result of $33 million of new borrowings related to certain international drilling
activities partially offset by $30 million classified as current maturities. (See Note 3 to the Consolidated Financial Statements). The estimated fair value of the Company's long-term debt, including current maturities of $30 million, at December 31, 1993 was $192 million based upon quoted market prices and, where such prices were not available, upon interest rates currently available to the Company at year end. (See Note 12 to the Consolidated Financial Statements).
OUTLOOK. While the wellhead natural gas price environment was, on average, stronger during the year 1993, there continues to exist a good deal of uncertainty as to the direction of future natural gas price trends. However, recent experiences continue to suggest a possible converging of the overall supply/demand relationship reflecting, at least partially, the significantly reduced level of drilling activity during recent years. Management remains confident that continually increasing recognition of natural gas as a more environmentally friendly source of energy along with the availability of significant domestically sourced supplies will result in further increases in demand and a strengthening of the overall natural gas market over time. Being primarily a natural gas producer, the Company is more significantly impacted by changes in natural gas prices than by changes in crude oil and condensate prices. (See 'Business - Other Matters - Energy Prices'). Based on the portion of the Company's anticipated natural gas volumes for which prices have not, in effect, been hedged using the futures market and long-term marketing contracts, the Company's net income and cash flow sensitivity to changing natural gas prices is approximately $7 million for each $.10 per Mcf change in average wellhead natural gas prices. Using various commodity price hedging mechanisms, the Company has, in effect, locked in prices for an average of about two-thirds of its anticipated wellhead natural gas volumes for the year 1994. This level of hedging may change during the remainder of 1994 and will change in future years.
Other factors representing positive impacts that are more certain continue to hold good potential for the Company in future periods. While the drilling qualification period for the tight gas sand federal income tax credit expired as of December 31, 1992, the Company has continued in 1993, and should continue in the future, to realize significant benefits associated with production from wells drilled during the qualifying period as it will be eligible for the federal income tax credit through the year 2002. However, all other factors remaining equal, the annual benefit, which was $65 million in 1993 and estimated to be approximately $40 million for 1994, is expected to continue to decline in future periods as production from the qualified wells declines. The drilling qualification period for a certain state severance tax exemption available on certain high cost natural gas revenues continues through the latter part of 1996. Consequently, new qualifying production will be added prospectively to that qualified at year end 1993. (See 'Business - Other Matters - Tight Gas Sand Tax Credit (Section 29) and Severance Tax Exemption'). Other natural gas marketing activities are also expected to continue to contribute meaningfully to financial results. However, the Company completed a fairly significant restructure of its other natural gas marketing portfolio during 1992 with the sale of a volumetric production payment of approximately 124 Bcfe (136 trillion British thermal units) for $326.8 million that was subsequently revised in 1993 (See 'Business - Marketing - Other Marketing' and Note 4 to Consolidated Financial Statements) and elimination of most delivery obligations under four long-term fixed price marketing contracts. The proceeds from the sale of the volumetric production payment added substantially to the financial flexibility of the Company supporting future development while the combined effect of all elements of the restructuring on net income has not been, and will not in the future be, significant. These factors are expected to contribute significantly to earnings, cash flow, and the ability of the Company to pursue the continuation of an active exploration, development and selective acquisition program.
The Company will continue to focus development and certain exploration expenditures in its core and other major producing areas, and include limited but meaningful exploratory exposure in areas outside of North America. (See 'Business - Exploration and Production' for additional information detailing the specific geographic locations of the related drilling programs). Early-in-year activity will be managed within an annual expected expenditure level of approximately $450 million. This early-in-year planning will address the continuing uncertainty with regard to the future of the
natural gas price environment and will be structured to maintain the flexibility necessary under the Company strategy of funding exploration, development and acquisition activities primarily from available internally generated cash flow. Expenditure plans for 1994 will continue to be focused toward certain areas that were not addressed as actively in the recent past due to the increased emphasis on tight gas sand drilling opportunities during 1991 and 1992 that were completed in early 1993. The Company will also be continuing expenditures in new areas outside of North America, primarily for additional development operations in Trinidad, possible new development operations in other countries, such as those currently being pursued in India, and the continued evaluation of coalbed methane recovery potential in France, Australia, China and certain other countries.
The level of exploration and development expenditures may vary in 1994 and will vary in future periods depending on energy market conditions and other related economic factors. Based upon existing economic and market conditions, the Company believes net operating cash flow and available financing alternatives in 1994 will be sufficient to fund its net investing cash requirements for the year. However, the Company has significant flexibility with respect to its financing alternatives and adjustment of its exploration and development expenditure plans as circumstances warrant. There are no material continuing commitments associated with expenditure plans.
ITEM 8.


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required hereunder is included in this report as set forth in the 'Index to Financial Statements' on page.
ITEM 9.

ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.



ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this Item regarding directors is set forth in the Proxy Statement under the caption entitled 'Election of Directors', and is incorporated herein by reference.
See list of 'Current Executive Officers of the Registrant' in Part I located elsewhere herein.
There are no family relationships among the officers listed, and there are no arrangements or understandings pursuant to which any of them were elected as officers. Officers are appointed or elected annually by the Board of Directors at its first meeting following the Annual Meeting of Shareholders, each to hold office until the corresponding meeting of the Board in the next year or until a successor shall have been elected, appointed or shall have qualified.
ITEM 11.

ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item is set forth in the Proxy Statement under the caption 'Compensation of Directors and Executive Officers', and is incorporated herein by reference.
ITEM 12.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this Item is set forth in the Proxy Statement under the captions 'Election of Directors' and 'Compensation of Directors and Executive Officers', and is incorporated herein by reference.
ITEM 13.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item is set forth in the Proxy Statement under the caption 'Compensation Committee Interlocks and Insider Participation', and is incorporated herein by reference.
PART IV
ITEM 14.

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(A)(1) AND (2) FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
See 'Index to Financial Statements' set forth on page.
(A)(3) EXHIBITS
See pages E-1 through E-3 for a listing of the exhibits.
(B) REPORTS ON FORM 8-K
No reports on Form 8-K were filed by the Company during the last quarter of 1993.
ENRON OIL & GAS COMPANY
PAGE Consolidated Financial Statements: Management's Responsibility for Financial Reporting---- Report of Independent Public Accountants--------------- Consolidated Statements of Income for Each of the Three Years in the Period Ended December 31, 1993---- Consolidated Balance Sheets -December 31, 1993 and 1992--------------------------------------------- Consolidated Statements of Shareholders' Equity for Each of the Three Years in the Period Ended December 31, 1993------------------------------ Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 1993------------------------------------ Notes to Consolidated Financial Statements------------- Supplemental Information to Consolidated Financial Statements----------------------------------------------- Financial Statement Schedules: Schedule V -Property, Plant and Equipment----------- S-1 Schedule VI -Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment---- S-2 Schedule VIII -Valuation and Qualifying Accounts and Reserves----------------------------------------- S-3 Schedule X -Supplemental Income Statement Information------------------------------------------- S-4 Other financial statement schedules have been omitted because they are inapplicable or the information required therein is included elsewhere in the consolidated financial statements or notes thereto.
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING
The following consolidated financial statements of Enron Oil & Gas Company and its subsidiaries were prepared by management which is responsible for their integrity, objectivity and fair presentation. The statements have been prepared in conformity with generally accepted accounting principles and accordingly include some amounts that are based on the best estimates and judgements of management.
Arthur Andersen & Co., independent public accountants, was engaged to audit the consolidated financial statements of Enron Oil & Gas Company and its subsidiaries and issue a report thereon. In the conduct of the audit, Arthur Andersen & Co. was given unrestricted access to all financial records and related data including minutes of all meetings of shareholders, the Board of Directors and committees of the Board. Management believes that all representations made to Arthur Andersen & Co. during the audit were valid and appropriate. Their audits of the years presented included developing an overall understanding of the Company's accounting systems, procedures and internal controls, and conducting tests and other auditing procedures sufficient to support their opinion on the financial statements. The report of Arthur Andersen & Co. appears on the following page.
The system of internal controls of Enron Oil & Gas Company and its subsidiaries is designed to provide reasonable assurance as to the reliability of financial records as represented in published interim and annual financial statements and for the protection of assets. This system includes, but is not limited to, written policies and guidelines including a published code for the conduct of business affairs, the careful selection and training of qualified personnel, and a documented organizational structure outlining the separation of responsibilities among management representatives and staff groups, augmented by a strong program of internal audit.
The adequacy of financial controls of Enron Oil & Gas Company and its subsidiaries and the accounting principles employed in financial reporting by the Company are under the general oversight of the Audit Committee of the Board of Directors. No member of this committee is an officer or employee of the Company. Both the independent public accountants and internal/contract auditors have direct access to the Audit Committee and meet with the committee from time to time to discuss accounting, auditing and financial reporting matters. Effective January 1, 1994, Arthur Andersen & Co. has been contracted to provide operational and internal control audit services previously handled by the internal audit staff of the Company.
It should be recognized that there are inherent limitations to the effectiveness of any system of internal control, including the possibility of human error and circumvention or override. Accordingly, even an effective system can provide only reasonable assurance with respect to the preparation of reliable financial statements. Furthermore, the effectiveness of an internal control system can change with circumstances.
It is management's opinion that, considering the criteria for effective internal control over financial reporting which consists of interrelated components including the control environment, risk-assessment process, control activities, information and communication systems, and monitoring, the Company maintained an effective system of internal control over the preparation of published interim and annual financial statements for all periods presented.
BEN B. BOYD WALTER C. WILSON FORREST E. HOGLUND Vice President and Senior Vice President and Chairman of the Board, Controller Chief Financial Officer President and Chief Executive Officer
Houston, Texas March 18, 1994
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Enron Oil & Gas Company:
We have audited the accompanying consolidated balance sheets of Enron Oil & Gas Company (a Delaware corporation) and subsidiaries as of December 31, 1993 and 1992, and the related consolidated statements of income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 1993. These financial statements and the schedules referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Enron Oil & Gas Company and subsidiaries as of December 31, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The financial statement schedules listed in the index to financial statements are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
As explained in Note 7 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 109, 'Accounting for Income Taxes', effective January 1, 1993, and applied the provisions of the statement retroactively.
ARTHUR ANDERSEN & CO.
Houston, Texas February 18, 1994 (except with respect to the matters discussed in Note 3, as to which the date is March 11, 1994)
ENRON OIL & GAS COMPANY CONSOLIDATED STATEMENTS OF INCOME (IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31, 1993 1992 1991 (RESTATED) NET OPERATING REVENUES Natural Gas Associated Companies----------- $ 279,921 $ 280,501 $ 275,362 Trade-------------------------- 225,241 108,487 46,241 Crude Oil, Condensate and Natural Gas Liquids Associated Companies----------- 38,953 38,775 41,237 Trade-------------------------- 16,881 20,152 21,599 Other----------------------------- 6,706 5,074 3,166 Total-------------------- 567,702 452,989 387,605 OPERATING EXPENSES Lease and Well-------------------- 59,344 49,406 49,922 Exploration----------------------- 36,921 33,278 31,470 Dry Hole-------------------------- 18,355 10,764 14,698 Impairment of Unproved Oil and Gas Properties---------------------- 20,467 15,136 12,791 Depreciation, Depletion and Amortization-------------------- 249,704 179,839 160,885 General and Administrative-------- 45,274 36,648 36,216 Taxes Other Than Income----------- 35,396 28,346 18,222 Total-------------------- 465,461 353,417 324,204 OPERATING INCOME--------------------- 102,241 99,572 63,401 OTHER INCOME------------------------- 19,953 2,561 11,768 INCOME BEFORE INTEREST EXPENSE AND TAXES------------------------------ 122,194 102,133 75,169 INTEREST EXPENSE Incurred Affiliate---------------------- - 1,747 9,503 Other-------------------------- 15,378 24,122 24,479 Capitalized----------------------- (5,457) (3,580) (4,482) Net Interest Expense----------- 9,921 22,289 29,500 INCOME BEFORE INCOME TAXES----------- 112,273 79,844 45,669 INCOME TAX BENEFIT------------------- (25,752) (17,736) (2,247) NET INCOME--------------------------- $ 138,025 $ 97,580 $ 47,916 EARNINGS PER SHARE OF COMMON STOCK------------------------------ $ 1.73 $ 1.26 $ .63 AVERAGE NUMBER OF COMMON SHARES------ 79,983 77,267 75,900
The accompanying notes are an integral part of these consolidated financial statements.
ENRON OIL & GAS COMPANY CONSOLIDATED BALANCE SHEETS (IN THOUSANDS)
AT DECEMBER 31, 1993 1992 (RESTATED) ASSETS CURRENT ASSETS Cash and Cash Equivalents--------- $ 103,129 $ 132,618 Accounts Receivable Associated Companies----------- 59,143 50,838 Trade-------------------------- 66,109 50,832 Inventories----------------------- 14,082 9,534 Other----------------------------- 6,962 3,190 Total----------------------- 249,425 247,012 OIL AND GAS PROPERTIES (Successful Efforts Method)---------------------- 2,772,220 2,475,371 Less: Accumulated Depreciation, Depletion and Amortization------ 1,226,175 1,007,360 Net Oil and Gas Properties---------------- 1,546,045 1,468,011 OTHER ASSETS------------------------- 15,692 15,989 TOTAL ASSETS------------------------- $ 1,811,162 $ 1,731,012 LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Accounts Payable Associated Companies----------- $ 13,250 $ 1,889 Trade-------------------------- 143,542 128,695 Accrued Taxes Payable------------- 17,354 9,911 Dividends Payable----------------- 4,795 4,800 Current Maturities of Long-Term Debt---------------------------- 30,000 - Other----------------------------- 8,989 49,421 Total----------------------- 217,930 194,716 LONG-TERM DEBT----------------------- 153,000 150,000 OTHER LIABILITIES-------------------- 9,477 8,972 DEFERRED INCOME TAXES---------------- 270,154 248,943 DEFERRED REVENUE--------------------- 227,528 301,395 COMMITMENTS AND CONTINGENCIES (Note 8) SHAREHOLDERS' EQUITY Common Stock, No Par, 80,000,000 Shares Authorized and Issued---- 200,800 200,800 Additional Paid In Capital-------- 417,531 421,747 Cumulative Foreign Currency Translation Adjustment---------- (6,855) (1,726) Retained Earnings----------------- 324,995 206,165 Common Stock Held in Treasury, 80,000 shares------------------- (3,398) - Total Shareholders' Equity---------------------- 933,073 826,986 TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY----------------------------- $ 1,811,162 $ 1,731,012
The accompanying notes are an integral part of these consolidated financial statements.
ENRON OIL & GAS COMPANY CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
ENRON OIL & GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
YEAR ENDED DECEMBER 31, 1993 1992 1991 CASH FLOWS FROM OPERATING ACTIVITIES (RESTATED) Reconciliation of Net Income to Net Operating Cash Inflows: Net Income------------------------ $ 138,025 $ 97,580 $ 47,916 Items Not Requiring (Providing) Cash Depreciation, Depletion and Amortization----------------- 249,704 179,839 160,885 Impairment of Unproved Oil and Gas Properties--------------- 20,467 15,136 12,791 Deferred Income Taxes---------- 25,612 (17,917) (11,997) Other, Net--------------------- 1,768 5,713 5,073 Exploration Expenses-------------- 36,921 33,278 31,470 Dry Hole Expenses----------------- 18,355 10,764 14,698 Gains On Sales of Oil and Gas Properties---------------------- (13,318) (6,037) (14,983) Other, Net------------------------ 1,242 (6,147) 614 Changes in Components of Working Capital and Other Liabilities Accounts Receivable------------ (24,586) (12,732) (821) Inventories-------------------- (4,548) 3,687 (19) Accounts Payable--------------- 26,208 46,327 381 Accrued Taxes Payable---------- 7,443 247 1,011 Other Liabilities-------------- 772 (2,886) (1,006) Other, Net--------------------- (44,443) 33,784 3,839 Changes in Components of Working Capital Associated with Investing and Financing Activities---------------------- 40,042 (74,232) (7,976) NET OPERATING CASH INFLOWS----------- 479,664 306,404 241,876 INVESTING CASH FLOWS Additions to Oil and Gas Properties---------------------- (383,064) (362,403) (211,673) Exploration Expenses-------------- (36,921) (33,278) (31,470) Dry Hole Expenses----------------- (18,355) (10,764) (14,698) Proceeds from Sale of Properties---------------------- 41,815 33,412 22,827 Proceeds from Sale of Volumetric Production Payment-------------- - 326,775 - Amortization of Deferred Revenue------------------------- (73,867) (25,380) - Changes in Components of Working Capital Associated with Investing Activities------------ (37,256) 74,232 7,976 Other, Net------------------------ (4,905) (3,686) (3,020) NET INVESTING CASH OUTFLOWS---------- (512,553) (1,092) (230,058) FINANCING CASH FLOWS Long-Term Debt Affiliate---------------------- - (132,836) (145,082) Other-------------------------- 33,000 (139,556) 149,114 Common Stock Issued--------------- - 111,861 - Dividends Paid-------------------- (19,200) (15,385) (15,180) Treasury Stock Purchased---------- (16,698) (1,827) - Proceeds from Sales of Treasury Stock--------------------------- 9,084 1,250 - Other, Net------------------------ (2,786) - (466) NET FINANCING CASH INFLOWS (OUTFLOWS)------------------------- 3,400 (176,493) (11,614) INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS------------------------ (29,489) 128,819 204 CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR------------------ 132,618 3,799 3,595 CASH AND CASH EQUIVALENTS AT END OF YEAR------------------------------- $ 103,129 $ 132,618 $ 3,799
The accompanying notes are an integral part of these consolidated financial statements.
ENRON OIL & GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DOLLARS IN THOUSANDS UNLESS OTHERWISE INDICATED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION. The consolidated financial statements of Enron Oil & Gas Company (the 'Company'), 80% of the outstanding common stock of which is owned by Enron Corp., include the accounts of all domestic and foreign subsidiaries. All material intercompany accounts and transactions have been eliminated. Certain reclassifications have been made to consolidated financial statements for prior years to conform with the current presentation.
CASH EQUIVALENTS. The Company records as cash equivalents all highly liquid short-term investments with maturities of three months or less. (See Note 3 'Long-Term Debt, Financing Arrangements with Enron Corp.')
OIL AND GAS OPERATIONS. The Company accounts for its natural gas and crude oil exploration and production activities under the successful efforts method of accounting.
Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with significant acquisition costs are assessed quarterly on a property-by-property basis and any impairment in value is recognized. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience, is amortized over the average holding period. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred.
Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. The costs of all development wells and related equipment used in the production of crude oil and natural gas are capitalized.
Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. Estimated future dismantlement, restoration and abandonment costs (classified as long-term liabilities), net of salvage values, are taken into account. Certain other assets are depreciated on a straight-line basis.
Inventories, consisting primarily of tubular goods and well equipment held for use in the exploration for, and development and production of crude oil and natural gas reserves, are carried at cost with selected adjustments made from time to time to recognize changes in condition value.
Natural gas revenues are recorded to recognize that during the course of normal production operations joint interest owners will, from time to time, take more or less than their ultimate share of natural gas volumes from jointly owned reservoirs. These volumetric imbalances are monitored over the life of the reservoir to achieve balancing, or minimize imbalances, by the time reserves are depleted. Final cash settlements are made, generally at the time a property is depleted, under one of a variety of arrangements generally accepted by the industry depending on the specific circumstances involved. The Company accrues revenues associated with undertakes and defers revenues associated with overtakes to recognize these potential ultimate imbalances.
ACCOUNTING FOR FUTURES CONTRACTS. Futures transactions are entered into as hedges of commodity prices associated with the sales and purchases of natural gas and crude oil, in order to mitigate the risk of market price fluctuations. Changes in the market value of futures transactions entered into as hedges are deferred until the gain or loss is recognized on the hedged transactions.
CAPITALIZED INTEREST COSTS. Certain interest costs have been capitalized as a part of the historical cost of unproved oil and gas properties. Interest costs capitalized during each of the three years in the period ended December 31, 1993 are set out in the Consolidated Statements of Income.
INCOME TAXES. Taxable income of the Company, excluding that of any foreign subsidiaries, is included in the consolidated federal income tax return filed by Enron Corp. Pursuant to a tax allocation agreement between the Company, the Company's subsidiaries and Enron Corp., either Enron Corp. will pay to the Company and each subsidiary an amount equal to the tax benefit realized in the Enron Corp. consolidated federal income tax return resulting from the utilization of the Company's or the subsidiary's net operating losses and/or tax credits, or the Company and each subsidiary will pay to Enron Corp. an amount equal to the federal income tax computed on its separate taxable income less the tax benefits associated with any net operating losses and/or tax credits generated by the Company or the subsidiary which are utilized in the Enron Corp. consolidated return. Enron Corp. will pay the Company and each subsidiary for the tax benefits associated with their net operating losses and tax credits utilized in the Enron Corp. consolidated return, provided that a tax benefit was realized except as discussed in the following paragraph, even if such benefits could not have been used by the Company or the subsidiary on a separately filed tax return.
In 1991, the Company and Enron Corp. modified the tax allocation agreement to provide that through 1992, the Company would realize the benefit of certain tight gas sand tax credits available to the Company on a stand alone basis. The Company has also entered into an agreement with Enron Corp. providing for the Company to be paid for all realizable benefits associated with tight gas sand tax credits concurrent with tax reporting and settlement for the periods in which they are generated.
The tax allocation agreement applies to the Company and each of its subsidiaries for all years in which the Company or any of its subsidiaries are or were included in the Enron Corp. consolidated return. Taxes for any foreign subsidiaries of the Company are calculated on a separate return basis.
The Company adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 109 -'Accounting for Income Taxes' effective January 1, 1993 and applied the provisions of the statement retroactively. The Company previously accounted for income taxes under the provisions of SFAS No. 96 which was superceded by SFAS No. 109. SFAS No. 109 retains the asset and liability approach for accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases.
FOREIGN CURRENCY TRANSLATION. For subsidiaries whose functional currency is deemed to be other than the U.S. dollar, asset and liability accounts are translated at year end rates of exchange and revenue and expenses are translated at average exchange rates prevailing during the year. Translation adjustments are included as a separate component of shareholders' equity.
EARNINGS PER SHARE. Earnings per share is computed on the basis of the average number of common shares outstanding during the periods.
2. NATURAL GAS AND CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS NET OPERATING REVENUES
Natural Gas Net Operating Revenues are comprised of the following:
1993 1992 1991 Wellhead Natural Gas Revenues Associated Companies(1)---------- $340,508(2) $223,249(2) $171,056 Trade---------------------------- 156,301 103,288 75,037 Total-------------------- $496,809 $326,537 $246,093 Other Natural Gas Marketing Activities Gross Revenues from: Associated Companies(3)------ $139,576 $186,600 $220,152 Trade------------------------ 135,606(4) 57,482(4) 7,215 Total-------------------- 275,182 244,082 227,367 Associated Costs from: Associated Companies(1)(5)-------------- 182,456(6) 133,170(6) 115,601 Trade------------------------ 66,273 52,283 36,011 Total-------------------- 248,729 185,453 151,612 Net---------------------- 26,453 58,629 75,755 NYMEX Commodity Price Hedging Gain (Loss)(7)----------------- (18,100) 3,822 (245) Total-------------------- $ 8,353 $ 62,451 $ 75,510
Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues are comprised of the following:
1993 1992 1991 Wellhead Crude Oil, Condensate and Natural Gas Liquids Revenues Associated Companies------------- $ 38,953 $ 38,474 $ 37,029 Trade---------------------------- 16,881 20,152 21,599 Total------------------------ $ 55,834 $ 58,626 $ 58,628 Other Crude Oil and Condensate Marketing Activities NYMEX Commodity Price Hedging Gain(7)------------------------ $ - $ 301 $ 4,208
(1) Wellhead Natural Gas Revenues in 1993, 1992 and 1991 include $129,504, $84,317 and $69,175, respectively, associated with deliveries by Enron Oil & Gas Company to Enron Oil & Gas Marketing, Inc., a wholly-owned subsidiary, reflected as a cost in Other Natural Gas Marketing Activities -Associated Costs.
(2) Includes $46,358 and $20,667 in 1993 and 1992, respectively, associated with the equivalent wellhead value of volumes delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended, net of transportation.
(3) Includes the effect of a price swap agreement with an Enron Corp. affiliated company which in effect fixed the price of certain sales.
(4) Includes $73,867 and $25,380 in 1993 and 1992, respectively, associated with the amortization of deferred revenues under the terms of volumetric production payment and exchange agreements effective October 1, 1992, as amended.
(5) Includes the effect of a price swap agreement with a third party which in effect fixed the price of certain purchases.
(6) Includes $65,042 and $23,977 in 1993 and 1992, respectively, for volumes delivered under volumetric production payment and exchange agreements effective October 1, 1992, as amended, including equivalent wellhead value, any applicable transportation costs and exchange differentials.
(7) Represents gain or loss associated with commodity futures transactions primarily with Enron Corp. affiliated companies based on NYMEX prices in effect on dates of execution, less customary transaction fees.
3. LONG-TERM DEBT
REVOLVING CREDIT AGREEMENT. In March 1994, the Company replaced an existing credit agreement with a Revolving Credit Agreement dated as of March 11, 1994, among the Company and the banks named therein (the 'Credit Agreement'). The Credit Agreement provides for aggregate borrowings of up to $100 million, with provisions for increases, at the option of the Company, up to $300 million. Advances under the Credit Agreement bear interest, at the option of the Company, based on a base rate, an adjusted CD rate or a Eurodollar rate. Each advance under the Credit Agreement matures on a date selected by the Company at the time of the advance, but in no event after January 15, 1998.
FINANCING ARRANGEMENTS WITH ENRON CORP. The Company engages in various transactions with Enron Corp. that are characteristic of a consolidated group under common control. Activities of the Company not internally funded from operations have been and may be funded from time to time by advances from Enron Corp. The Company entered into an agreement with Enron Corp., effective October 12, 1989 (as amended effective September 29, 1992), under which the Company may borrow funds from Enron Corp. at a representative market rate of interest on a revolving basis. During 1993, there were no funds borrowed by the Company under this agreement. Any loan balance that may be outstanding from time to time is payable on demand but no later than September 29, 1995, the maturity date of this agreement. Any balances outstanding are classified as long-term based on the Company's intent and ability to refinance such amounts using available borrowing capacity. Interest expense recorded in 1992 and 1991 under the terms of this agreement totaled $.1 million and $.2 million, respectively. There was no interest expense relating to this agreement recorded in 1993.
The Company also entered into an agreement with Enron Corp., effective October 12, 1989 (as amended effective September 29, 1992), which provides the Company the option of depositing any excess funds that may be available from time to time with Enron Corp. with interest at a representative market rate during the periods the funds were held by Enron Corp. Interest income recorded in 1992 and 1991 under the terms of this agreement totaled $1.4 million and $.3 million, respectively. Effective January 1, 1993, the Company executed a promissory note at a fixed interest rate of 7% with Enron Corp. providing for the investment of funds temporarily surplus to the Company from time to time with Enron Corp. Daily outstanding balances of funds advanced to Enron Corp. under this note averaged $60.3 million during 1993 with a balance of $96.6 million outstanding and included in Cash and Cash Equivalents at December 31, 1993. Interest income recorded in 1993 under the terms of this note totaled $4.4 million.
OTHER LONG-TERM DEBT. Other long-term debt at December 31 consisted of the following:
1993 1992 Loans Payable-------------------- $ 50,000 $ 50,000 Senior Notes--------------------- 70,000 100,000 Promissory Note------------------ 33,000 - Total---------------- $ 153,000 $ 150,000
The Loans Payable are due in 1995 and bear interest at a variable rate based on the London Interbank Offered Rate which has, in effect, been converted to fixed interest rates ranging from 8.92% to 8.98% through maturity using interest rate swap agreements in equivalent dollar amounts.
The Senior Notes bear interest at 9.1% with principal repayments of $30 million due in 1996 and $20 million due in 1997 and 1998. A principal repayment of $30 million is due in 1994 and is classified as current maturities of long-term debt at December 31, 1993.
The Promissory Note is payable by one of the Company's subsidiaries to a bank, bears interest at 3 3/8% and represents interim financing under Section 936(d)(4) of the Internal Revenue Code of 1986, as amended, of a project involving the development of gas and oil fields. The note is due the earlier of April 30, 1994, as extended, or the closing date of the permanent financing and is collateralized with a letter of credit issued by a bank on behalf of the subsidiary and guaranteed by the Company. The note
is classified as long-term based on the subsidiary's intent and ability to convert the balance of the note to permanent long-term financing. In March 1994, the subsidiary received two advances aggregating $31 million under a credit agreement dated as of March 8, 1994, between the subsidiary and a financial institution. The credit agreement provides for aggregate borrowings of up to $75 million. One of the advances is in the amount of $16 million, bears interest at a fixed rate of 4.52% and is due in 1998. The other advance is in the amount of $15 million, bears interest at a floating rate that resets quarterly equal to 84% of the LIBID Rate which is 1/8 of 1% less than the London Interbank Offered Rate and is due in 1998. Both advances are collaterized with a letter of credit issued by a bank on behalf of the subsidiary and guaranteed by the Company. The advances were used to partially repay the Promissory Note.
There were no balances outstanding at December 31, 1993 and 1992 under a commercial paper program initiated in 1990. The proceeds from the commercial paper program outstanding from time to time are used to fund current transactions.
Certain of the borrowings described above contain covenants requiring the maintenance of certain financial ratios and limitations on liens, debt issuance and dispositions of assets.
In September 1991, the Company filed with the Securities and Exchange Commission a registration statement providing for the issuance and sale from time to time of up to $250 million of debt securities to the public. As of December 31, 1993, no debt securities had been issued under this registration statement.
4. DEFERRED REVENUE
In September 1992, the Company sold a volumetric production payment for $326.8 million to a limited partnership of which an Enron Corp. affiliated company is general partner with a 1% interest. Under the terms of the production payment agreements, the Company conveyed a real property interest of approximately 124 billion cubic feet equivalent ('Bcfe') (136 trillion British thermal units) of natural gas and other hydrocarbons in the Big Piney area of Wyoming. The natural gas and other hydrocarbons were originally scheduled to be produced and delivered over a period of forty-five months which period commenced October 1, 1992. Effective October 1, 1993, the agreements were amended providing for the extension of the original term of the volumetric production payment through March 31, 1999 and including a revised schedule of daily quantities of hydrocarbons to be delivered which is approximately one-half of the original schedule. The revised schedule will total approximately 89.1 Bcfe (97.8 trillion British thermal units) versus approximately 87.9 Bcfe (96.4 trillion British thermal units) remaining to be delivered under the original agreement. Daily quantities of hydrocarbons no longer required to be delivered under the revised schedule during the period from October 1, 1993 through June 30, 1996 are available for sale by the Company. The Company retains responsibility for its working interest share of the cost of operations. The Company also entered into a separate agreement with the same limited partnership whereby it has agreed to exchange volumes owned by the Company in the Midcontinent area and the Texas Gulf Coast area for equivalent volumes produced and owned by the limited partnership in the Big Piney area. The costs incurred, if any, to effect redeliveries pursuant to such exchange are borne by the Company. A portion of the proceeds of the sale was used to repay a portion of the Company's long-term debt, with surplus funds advanced to Enron Corp. under a note agreement which facilitates the deposit of funds temporarily surplus to the Company. The Company accounted for the proceeds received in the transaction as deferred revenue which is being amortized into revenue and income as natural gas and other hydrocarbons are produced and delivered during the term, as revised, of the volumetric production payment. Annual remaining amortization of deferred revenue, based on revised
scheduled deliveries under the volumetric production payment agreement, as amended, at December 31, 1993 was as follows:
1994--------------------------------- $ 43,344 1995--------------------------------- 43,344 1996--------------------------------- 43,463 1997--------------------------------- 43,344 1998--------------------------------- 43,344 1999--------------------------------- 10,689 Total------------------------ $ 227,528
5. SHAREHOLDERS' EQUITY
In August 1992, the Company completed the offering and sale of 4.1 million shares of common stock. The shares were priced to the public at $28.50 per share. Net proceeds, after underwriting commissions and expenses, totaled approximately $112 million and were used primarily to repay long-term debt.
In December 1992, the Board of Directors of the Company approved the reduction of the authorized common shares from 100 million to 80 million shares and cancelled the authorization for preferred shares. Such actions were approved by the shareholders in May 1993.
Also in December 1992, the Board of Directors of the Company approved the purchase of up to 250,000 shares of common stock of the Company for, but not limited to, meeting obligations associated with stock option grants to qualified employees pursuant to the Enron Oil & Gas Company 1992 Stock Plan. (See Note 8 'Commitments and Contingencies -Enron Oil & Gas Company 1992 Stock Plan'). At December 31, 1993, 80,000 shares were held in treasury under this authorization.
In February 1994, the Board of Directors authorized submission of a resolution to shareholders for approval at their annual meeting in May 1994 that would, contingent upon the Board of Directors of the Company declaring, on or before May 3, 1995, a stock split of either two-for-one or three-for-two, amend the Restated Certificate of Incorporation of the Company to increase the total number of authorized shares of the common stock of the Company from 80 million to 160 million shares in the event of a two-for-one stock split or to 120 million shares in the event of a three-for-two stock split. Such charter amendment, if adopted, will become effective when the appropriate Certificate of Amendment to the Company's Restated Certificate of Incorporation is filed with the Secretary of State of Delaware, which filing will only be authorized at such time as the Board of Directors takes the requisite action to approve either a two-for-one or a three-for-two stock split in either case effected as a dividend which action, if to be carried out under this resolution, must occur on or before May 3, 1995.
6. TRANSACTIONS WITH ENRON CORP. AND RELATED PARTIES
NATURAL GAS AND CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS NET OPERATING REVENUES. Wellhead Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Revenues and Other Natural Gas and Other Crude Oil and Condensate Marketing Activities include revenues from and associated costs paid to various subsidiaries and affiliates of Enron Corp. pursuant to contracts which, in the opinion of management, are no less favorable than could be obtained from third parties. Other Natural Gas and Other Crude Oil and Condensate Marketing Activities also include certain price swap and futures transactions with Enron Corp. affiliated companies which, in the opinion of management, are no less favorable than could be obtained from third parties. (See Note 2 'Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues').
GENERAL AND ADMINISTRATIVE EXPENSES. The Company is charged by Enron Corp. for all direct costs associated with its operations. Such direct charges, excluding benefit plan charges (See Note 8 'Commitments and Contingencies -Employee Benefit Plans'), totaled $11.5 million, $4.9 million and $7.4 million for the years ended December 31, 1993, 1992 and 1991, respectively. Management believes that these charges are reasonable.
Additionally, certain administrative costs not directly charged to any Enron Corp. operations or business segments are allocated to the entities of the consolidated group. Allocation percentages are generally determined utilizing weighted average factors derived from property gross book value, net operating revenues and payroll costs. Effective January 1, 1989, the Company entered into an agreement with Enron Corp., with an initial term of five years, providing for, among other things, an annual cap of $8.0 million to be applied to indirect allocated charges subject to adjustment for inflation and certain changes in the allocation bases of the Company. Approximately $7.9 million, $9.5 million, and $9.4 million were charged to the Company for indirect general and administrative expenses for the years ended December 31, 1993, 1992 and 1991, respectively. Management believes the indirect allocated charges for the numerous types of support services provided by the corporate staff are reasonable. Effective January 1, 1994, the Company and Enron Corp. entered into a new services agreement pursuant to which Enron Corp. will, among other things, provide for the Company similar services substantially identical in nature and quality to those provided under terms of the previous agreement. The Company has agreed to pay and to reimburse Enron Corp. on bases essentially consistent with those included in the previous agreement, except that allocated indirect costs are subject to an annual maximum of $6.7 million for the year 1994 with any increase in such maximum for subsequent years not to exceed 7.5% per year. The new services agreement is for an initial term of five years through December 1998 and will continue thereafter until terminated by either party.
FINANCING. See Note 3 'Long-Term Debt' for a discussion of financing arrangements with Enron Corp.
7. INCOME TAXES
As discussed in Note 1, effective January 1, 1993, the Company adopted SFAS No. 109 and applied the provisions of the statement retroactively. Under the provisions of SFAS No. 109, the effect of a change in a tax rate is recognized in income for the period that includes the date of enactment of such change. Consequently, the previously reported net income for 1991 was restated to $47.9 million ($.63 per share) from $54.9 million ($.72 per share), a reduction of $7.0 million primarily to recognize the enactment of a change in the computation of certain state franchise taxes, a portion of which is treated as an income tax under SFAS No. 109. Net income for 1992 and 1993 was not affected by the restatement. The Company's consolidated balance sheet at December 31, 1992 was also restated to reflect the increase to Deferred Income Taxes of $7.0 million and the corresponding decrease to Retained Earnings of an equal amount. In August 1993, the corporate federal income tax rate increased from 34% to 35% retroactive to January 1, 1993 resulting in an increase to the Company's 1993 deferred income tax provision of approximately $5.9 million with a corresponding increase to the Company's deferred income tax liability of an equal amount and a decrease of approximately $1.2 million to the Company's 1993 current income tax benefit.
The principal components of the Company's net deferred income tax liability at December 31, 1993 and 1992 were as follows (in thousands):
1993 1992 (RESTATED) Deferred Income Tax Assets Non-Producing Leasehold Costs------ $ 5,234 $ 4,661 Seismic Costs Capitalized for Tax------------------------------ 5,643 6,505 Other------------------------------ 6,337 13,167 Total Deferred Income Tax Assets----------------------- 17,214 24,333 Deferred Income Tax Liabilities Oil & Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization------- 276,422 253,009 Capitalized Interest--------------- 6,866 4,604 Other------------------------------ 4,080 15,663 Total Deferred Income Tax Liabilities------------------ 287,368 273,276 Net Deferred Income Tax Liability-------------------- $ 270,154 $ 248,943
The components of income (loss) before income taxes were as follows:
[CAPTION] 1993 1992 1991 United States------------------------ $ 117,460 $ 74,226 $ 49,187 Foreign------------------------------ (5,187) 5,618 (3,518) Total------------------------ $ 112,273 $ 79,844 $ 45,669
Total income tax provision (benefit) was as follows:
1993 1992 1991 (RESTATED) Current: Federal-------------------------- $ (52,555) $ (292) $ 9,226 State---------------------------- 5 2 - Foreign-------------------------- 1,186 471 524 Total------------------------ (51,364) 181 9,750 Deferred: Federal-------------------------- 20,845 (21,729) (23,917) State---------------------------- 4,357 3,119 11,962 Foreign-------------------------- 410 693 (42) Total------------------------ 25,612 (17,917) (11,997) Income Tax Benefit----------------- $ (25,752) $ (17,736) $ (2,247)
The differences between taxes computed at the U.S. federal statutory rate and the Company's effective rate were as follows:
1993 1992 1991 (RESTATED) Statutory Federal Income Tax--------- $ 39,296 $ 27,147 $ 15,528 State Income Tax, Net of Federal Benefit---------------------------- 2,835 2,059 877 Income Tax Related to Foreign Operations------------------------- 3,461 (1,649) 1,677 Tight Gas Sand Federal Income Tax Credits---------------------------- (65,172) (42,500) (16,926) Revision of Prior Years' Tax Estimates-------------------------- (12,060) (2,842) (10,461) SFAS No. 109 Restatement------------- - - 7,018 Federal Tax Rate Increase------------ 5,875 - - Other-------------------------------- 13 49 40 Income Tax Benefit--------------- $ (25,752) $ (17,736) $ (2,247)
Current income tax receivable from (payable to) Enron Corp. at December 31, 1993, 1992 and 1991 amounted to $(6,892), $5,619 and $(4,522), respectively.
The Company has an alternative minimum tax (AMT) credit carryforward of $2.7 million which can be used to offset regular income taxes payable in future years. The AMT credit carryforward has an indefinite carryforward period.
The Company's foreign subsidiaries' undistributed earnings of approximately $45 million at December 31, 1993 are considered to be indefinitely invested outside the U.S. and, accordingly, no U.S. federal or state income taxes have been provided thereon. Upon distribution of those earnings in the form of dividends, the Company may be subject to both foreign withholding taxes and U.S. income taxes, net of allowable foreign tax credits. Determination of any potential amount of unrecognized deferred income tax liabilities is not practicable.
In 1991, the Company recognized for financial reporting purposes the benefits attributable to the utilization of a previously unrecognized separate company net operating loss carryforward resulting in a tax benefit of approximately $7 million reflected in 1991 net income.
8. COMMITMENTS AND CONTINGENCIES
EMPLOYEE BENEFIT PLANS. Employees of the Company are covered by various retirement, stock purchase and other benefit plans of Enron Corp. During each of the years ended December 31, 1993, 1992 and 1991, the Company was charged $4.5 million, $3.6 million and $3.6 million, respectively, for all such benefits, including pension expense totalling $.5 million, $.5 million and $.4 million, respectively, by Enron Corp.
As of September 30, 1993, the most recent valuation date, the plan net assets of the Enron Corp. defined benefit plan in which the employees of the Company participate exceeded the actuarial present value of projected plan benefit obligations by approximately $25.3 million. The assumed discount rate, rate of return on plan assets and rate of increases in wages used in determining the actuarial present value of projected plan benefits were 7.0%, 10.5% and 4.0%, respectively.
The Company also has in effect a pension and a savings plan related to its Canadian and Trinidadian subsidiaries. Activity related to these plans is not significant to the Company's operations.
The Company provides certain medical, life insurance and dental benefits to eligible employees who retire under the Enron Corp. Retirement Plan and their eligible surviving spouses. Effective January 1, 1993, the Company adopted the provisions of SFAS No. 106 'Employers' Accounting for Postretirement Benefits Other Than Pensions'. The standard requires that employers providing postretirement benefits accrue those costs over the service lives of the employees expected to be eligible to receive such benefits. Such costs were previously recorded on a pay-as-you-go basis. The net periodic cost under SFAS No. 106 for 1993 was approximately $1.0 million, including service cost, interest cost and amortization of transition obligation in the amounts of $.1 million, $.5 million and $.4 million, respectively. The transition obligation existing at January 1, 1993 is being amortized over an average period of 19 years. The adoption of SFAS No. 106 did not have a material impact on the Company's results of operations.
The accumulated postretirement benefit obligation ('APBO') existing at December 31, 1993 totaled $8.7 million, of which $7.2 million is applicable to current retirees and current employees eligible to retire. The measurement of the APBO assumes a 7% discount rate and a health care cost trend rate of 13% in 1993 decreasing to 5% by the year 2005 and beyond. A 1% increase in the health care cost trend rate would have the effect of increasing the APBO and the net periodic expense by approximately $.8 million and $.1 million, respectively. The Company does not currently intend to prefund its obligations under its postretirement welfare benefit plans.
ENRON OIL & GAS COMPANY 1992 STOCK PLAN. In December 1991, the Board of Directors of the Company adopted the Enron Oil & Gas Company 1992 Stock Plan (the 'Stock Plan'). The Stock Plan was approved by the shareholders in May 1992. Under the Stock Plan, employees of the
Company and its subsidiaries may be granted rights to purchase shares of common stock of the Company generally at a price not less than the market price of the stock at the date of grant. Options granted under the Stock Plan vest to the employee over a period of time based on the nature of the grants and as defined in the individual grant agreements.
The following table sets forth Stock Plan transactions for the years ended December 31:
NUMBER OF STOCK OPTIONS 1993 1992 Outstanding at January 1------------- 1,954,025 - Granted-------------------------- 460,300 2,024,025 Exercised------------------------ (335,925) (63,750) Forfeited------------------------ (16,000) (6,250) Outstanding at December 31 (Grant Prices of $18.50-$47.63 per Share)- 2,062,400 1,954,025 Available for Grant at December 31--- 537,925 982,225
At December 31, 1993, 1,249,975 of the Stock Plan options outstanding were vested. Of the remaining unvested Stock Plan options, approximately 377,550; 201,750; 157,375 and 75,750 vest in the years 1994, 1995, 1996 and 1997, respectively.
During 1993 and 1992, the Company purchased 335,925 and 63,750 of its common shares, respectively, and simultaneously delivered such shares upon the exercise of stock options. The difference between the cost of the treasury shares and the exercise price of the options, net of federal income tax benefit of $2.8 million, is reflected as an adjustment to Additional Paid In Capital. In addition in October 1993, the Company commenced a stock repurchase program authorized by the Board of Directors to facilitate the availability of treasury shares of common stock for the settlement of employee stock option exercises pursuant to, but not limited to, the Enron Oil & Gas Company 1992 Stock Plan. At December 31, 1993, 80,000 shares were held in treasury under this authorization. (See Note 5 'Shareholders' Equity').
Pursuant to an amendment to and extension of an employment agreement with the Chairman of the Board, President and Chief Executive Officer of the Company (the 'Chairman'), as of January 1, 1992, the Chairman agreed to the cancellation of 1,000,000 previously issued stock appreciation right ('SAR') units. The Chairman was granted 1,110,000 stock options pursuant to the 1992 Stock Plan. These options have a grant price of $18.50 per share; 1,000,000 of the options follow the same vesting schedule as did the SAR unit grant, 100,000 options vest over four years and the remaining 10,000 options vested in one year since such options were granted in lieu of part of the Chairman's 1991 cash bonus. In addition, the Chairman was issued in May 1992, 463,320 shares of Enron Corp. common stock. Such number of shares reflects the effect of a two-for-one split of such stock on August 16, 1993. Of these shares, 370,656 shares are restricted until such shares vest on the earlier to occur of five years after their date of grant or when the Chairman commences receiving benefits from one or more of the qualified pension plans sponsored by Enron Corp.
In February 1994, the Board of Directors of the Company adopted the Enron Oil & Gas Company 1994 Stock Plan (the '1994 Stock Plan'). Under the 1994 Stock Plan, employees of the Company and its subsidiaries may be granted rights to purchase shares of common stock of the Company generally at a price not less than the market price of the stock at the date of grant. Options granted under the 1994 Stock Plan vest to the employee over a period of time based on the nature of the grants and as defined in the individual grant agreements. The number of shares available for granting awards under the 1994 Stock Plan is 1,000,000 shares subject to certain adjustments. It is the intention of the Company that grants under the 1994 Stock Plan will be primarily to non-executive employees.
LETTERS OF CREDIT. At December 31, 1993 and 1992, the Company had letters of credit outstanding totalling approximately $46.2 and $52.9 million, respectively. The letters of credit outstanding at December 31, 1993 include $33 million issued in connection with a promissory note between one of
the Company's subsidiaries and a bank. The letters of credit outstanding at December 31, 1992 included $40 million issued in December 1992 in connection with the acquisition of producing properties in Canada, which acquisition was subsequently funded in early 1993. The related liability at December 31, 1992 for the acquisition was included in Other Current Liabilities.
CONTINGENCIES. There are various suits and claims against the Company having arisen in the ordinary course of business. However, management does not believe these suits and claims will individually or in the aggregate have a material adverse effect on the Company's financial condition or results of operations. TransAmerican Natural Gas Corporation ('TransAmerican') has filed a petition against the Company and Enron Corp. alleging breach of contract, tortious interference with contract, misappropriation of trade secrets and violation of state antitrust laws. The petition, as amended, seeks actual damages of $100 million plus exemplary damages of $300 million. The Company has answered the petition and is actively defending the matter; in addition, the Company has filed counterclaims against TransAmerican and a third-party claim against its sole shareholder, John R. Stanley, alleging fraud, negligent misrepresentation and breach of state antitrust laws. Trial, originally set for February 7, 1994, is now set for September 12, 1994. Although no assurances can be given, the Company believes that the claims made by TransAmerican are totally without merit, that the ultimate resolution of the matter will not have a materially adverse effect on its financial condition or results of operations, and that such ultimate resolution could result in a recovery to the Company. The Company has been named as a potentially responsible party in certain Comprehensive Environmental Response Compensation and Liability Act proceedings. However, management does not believe that any potential assessments resulting from such proceedings will individually or in the aggregate have a materially adverse effect on the financial condition or results of operations of the Company.
9. CASH FLOW INFORMATION
Gains on sales of certain oil and gas properties in the amount of $13.3 million, $6.0 million and $15.0 million are required to be removed from Net Income in connection with determining Net Operating Cash Inflows while the related proceeds are classified as investing cash flows for the years ended December 31, 1993, 1992 and 1991, respectively. However, current accounting guidelines will not permit the relevant federal income tax impact of these transactions to be reclassified to investing cash flows. The current federal income tax impact of these sales transactions was calculated by the Company to be $8.2 million, $8.2 million and $5.1 million for the years ended December 31, 1993, 1992 and 1991, respectively, which entered into the overall calculation of current federal income tax. The Company believes that this federal income tax impact should be considered in analyzing the elements of the cash flow statement.
Cash paid for interest and paid (received) for income taxes was as follows for the years ended December 31:
1993 1992 1991 Interest (net of amount capitalized)----------------------- $ 10,517 $ 21,576 $ 30,967 Income taxes------------------------- (67,733) 7,365 6,618
10. BUSINESS SEGMENT INFORMATION
The Company's operations are all natural gas and crude oil exploration and production related. Accordingly, such operations are classified as one business segment. Financial information by geographic area is presented below for the years ended December 31, or at December 31:
1993 1992 1991 Gross Operating Revenues United States-------------------- $ 640,205 $ 521,128 $ 436,856 Foreign-------------------------- 46,722 32,997 33,186 Total(1)--------------------- $ 686,927 $ 554,125 $ 470,042 Operating Income (Loss) United States-------------------- $ 112,686 $ 109,515 $ 77,333 Foreign-------------------------- (10,445) (9,943) (13,932) Total------------------------ $ 102,241 $ 99,572 $ 63,401 Identifiable Assets United States-------------------- $1,564,330 $1,568,093 $1,309,967 Foreign-------------------------- 246,832 162,919 145,641 Total------------------------ $1,811,162 $1,731,012 $1,455,608
(1) Not deducted are natural gas associated costs of $119,225, $101,136 and $82,437 in 1993, 1992 and 1991, respectively.
11. OTHER INCOME
Other income consisted of the following for the years ended December 31:
1993 1992 1991 Gains on Sales of Oil and Gas Properties------------------------- $ 13,318 $ 6,037 $ 14,983 Litigation Reserve Accruals---------- (2,520) (2,194) (1,200) Interest Income---------------------- 5,789 1,555 424 Settlement of Natural Gas Contracts-------------------------- 4,248 - - Other, Net--------------------------- (882) (2,837) (2,439) Total------------------------ $ 19,953 $ 2,561 $ 11,768
12. CONCENTRATIONS OF CREDIT RISK AND ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS
ACCOUNTS RECEIVABLE. Substantially all of the Company's accounts receivable at December 31, 1993 result from crude oil and natural gas sales and/or joint interest billings to affiliate and third party companies in the oil and gas industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. In determining whether or not to require collateral from a customer or joint interest owner, the Company analyzes the entity's net worth, cash flows, earnings, and credit ratings. Receivables are generally not collateralized. Historical credit losses incurred on receivables by the Company have been immaterial.
LONG-TERM DEBT. At December 31, 1993, the Company had $153 million of long-term debt and $30 million of current maturities outstanding. (See Note 3 'Long-Term Debt'). The estimated fair value of such debt, including current maturities, at December 31, 1993 was approximately $192 million. The fair value of long-term debt is the value the Company would have to pay to retire the debt, including any premium or discount to the debtholder for the differential between the stated interest rate and the year-end market rate. The fair value of long-term debt is based upon quoted market prices and, where such quotes were not available, upon interest rates available to the Company at year-end.
INTEREST RATE SWAP AGREEMENTS. In early 1992, the Company entered into $75 million in notional amount of interest rate swap agreements to hedge certain floating interest rate exposure in 1992 and 1993. This floating rate exposure arises from interest-bearing debt with interest payments subject to floating interest rates. (See Note 3 'Long-Term Debt'). Effective January 1, 1993, Enron Corp. assumed the Company's remaining obligations under these swap agreements.
At December 31, 1993, the Company had outstanding interest rate swaps with notional principal amounts of $50 million which terminate April 1995. The estimated fair value of the outstanding swap agreements at December 31, 1993 was a negative $3.3 million. The fair value of interest rate swap agreements is based upon termination values obtained from third parties.
FOREIGN CURRENCY CONTRACTS. The Company enters into foreign currency contracts from time to time to hedge specific currency exposure from commercial transactions. At December 31, 1993, there were no foreign currency contracts outstanding.
PRICE RISK MANAGEMENT. During 1990 and 1991, the Company entered into certain price swap agreements to, in effect, hedge the market risk caused by fluctuations in the price of natural gas. The agreements call for the Company to make payments to (or receive payments from) the other party based upon the differential between a fixed and a variable price for natural gas as specified by the contract. The current swap agreements run for periods of up to ten years expiring in 2000 and have a notional contract amount of approximately $299 million at December 31, 1993.
While notional contract amounts are used to express the magnitude of price and interest rate swap agreements, the amounts potentially subject to credit risk, in the event of nonperformance by the third parties, are substantially smaller. The Company does not anticipate nonperformance by the third parties.
ENRON OIL & GAS COMPANY SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (IN THOUSANDS EXCEPT PER SHARE AMOUNTS UNLESS OTHERWISE INDICATED) (UNAUDITED EXCEPT FOR RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES)
OIL AND GAS PRODUCING ACTIVITIES
The following disclosures are made in accordance with SFAS No. 69 - 'Disclosures about Oil and Gas Producing Activities':
OIL AND GAS RESERVES. Users of this information should be aware that the process of estimating quantities of 'proved' and 'proved developed' crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.
Proved reserves represent estimated quantities of crude oil, condensate, natural gas and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made.
Proved developed reserves are proved reserves expected to be recovered, through wells and equipment in place and under operating methods being utilized at the time the estimates were made.
Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices and production volumes. Canadian reserves, as presented on a net basis, assume prices and royalty rates in existence at the time the estimates were made, and the Company's estimate of future production volumes. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause the Company's share of future production from Canadian reserves to be materially different from that presented.
Estimates of proved and proved developed reserves at December 31, 1993, 1992 and 1991 were based on studies performed by the Company's engineering staff for reserves in both the United States and Canada. Opinions by DeGolyer and MacNaughton, independent petroleum consultants, for the years ended December 31, 1993, 1992 and 1991 covering producing areas containing 65%, 69% and 73%, respectively, of proved reserves of the Company on a net-equivalent-cubic-feet-of-gas basis, indicate that the estimates of proved reserves prepared by the Company's engineering staff for the properties reviewed by DeGolyer and MacNaughton, when compared in total on a net-equivalent- cubic-feet-of-gas basis, do not differ materially from the estimates prepared by DeGolyer and MacNaughton. Such estimates by DeGolyer and MacNaughton in the aggregate varied by not more than 5% from those prepared by the Company's engineering staff. All reports by DeGolyer and MacNaughton were developed utilizing geological and engineering data provided by the Company.
No major discovery or other favorable or adverse event subsequent to December 31, 1993 is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.
The following table sets forth the Company's net proved and proved developed reserves at December 31 for each of the four years in the period ended December 31, 1993, and the changes in the net proved reserves for each of the three years in the period then ended as estimated by the Company's engineering staff.
NET PROVED AND PROVED DEVELOPED RESERVE SUMMARY
CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES. The following table sets forth the capitalized costs relating to the Company's natural gas and crude oil producing activities at December 31, 1993 and 1992:
1993 1992 Proved properties-------------------- $ 2,675,419 $ 2,396,601 Unproved properties------------------ 96,801 78,770 Total---------------------------- 2,772,220 2,475,371 Accumulated depreciation, depletion and amortization------------------- (1,226,175) (1,007,360) Net capitalized costs---------------- $ 1,546,045 1,468,011
COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES. The acquisition, exploration and development costs disclosed in the following tables are in accordance with definitions in SFAS No. 19 - 'Financial Accounting and Reporting by Oil and Gas Producing Companies'.
Acquisition costs include costs incurred to purchase, lease, or otherwise acquire property.
Exploration costs include exploration expenses, additions to exploration wells in progress, and depreciation of support equipment used in exploration activities.
Development costs include additions to production facilities and equipment, additions to development wells in progress and related facilities, and depreciation of support equipment and related facilities used in development activities.
The following tables set forth costs incurred related to the Company's oil and gas activities for the years ended December 31:
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES(1). The following tables set forth results of operations for oil and gas producing activities for the years ended December 31:
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES. The following information has been developed utilizing procedures prescribed by SFAS No. 69 and based on crude oil and natural gas reserve and production volumes estimated by the engineering staff of the Company. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.
The future cash flows presented below are based on sales prices, cost rates, and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.
Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.
The following table sets forth the standardized measure of discounted future net cash flows from projected production of the Company's crude oil and natural gas reserves at December 31, for the years ended December 31:
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS. The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for each of the three years in the period ended December 31, 1993.
SCHEDULE V
S-1
SCHEDULE VI
ENRON OIL & GAS COMPANY SCHEDULE VI -- ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (IN THOUSANDS)
S-2
SCHEDULE VIII
S-3
SCHEDULE X
ENRON OIL & GAS COMPANY SCHEDULE X -- SUPPLEMENTAL INCOME STATEMENT INFORMATION FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (IN THOUSANDS)
COLUMN A COLUMN B
CHARGED TO EXPENSES ITEM 1993 1992 1991 Maintenance and repairs-------------- $ 8,198 $ 7,169 $ 7,107 Taxes, other than payroll and income taxes Property-------------------------- $ 12,525 $ 11,488 $ 6,401 Production/Severance-------------- 19,578 11,985 9,262 Franchise------------------------- 563 2,788 575 Other----------------------------- 107 32 124 Total-------------------------- $ 32,773 $ 26,293 $ 16,362
S-4
EXHIBITS
Exhibits not incorporated herein by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated herein by reference to the Company's Form S-1 Registration Statement, Registration No. 33-30678, filed on August 24, 1989 ('Form S-1'), or as otherwise indicated.
E-4
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED, ON THE 18TH DAY OF MARCH, 1994.
ENRON OIL & GAS COMPANY (REGISTRANT)
By /s/ WALTER C. WILSON (WALTER C. WILSON) SENIOR VICE PRESIDENT AND CHIEF FINANCIAL OFFICER
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BY THE FOLLOWING PERSONS ON BEHALF OF REGISTRANT AND IN THE CAPACITIES WITH ENRON OIL & GAS COMPANY INDICATED AND ON THE 18TH DAY OF MARCH, 1994. SIGNATURE TITLE /s/ FORREST E. HOGLUND Chairman of the Board, President and (FORREST E. HOGLUND) Chief Executive Officer and Director (Principal Executive Officer)
/s/ WALTER C. WILSON Senior Vice President and Chief (WALTER C. WILSON) Financial Officer (Principal Financial Officer)
/s/ BEN B. BOYD Vice President and Controller (BEN B. BOYD) (Principal Accounting Officer)
FRED C. ACKMAN * Director (FRED C. ACKMAN)
RICHARD D. KINDER * Director (RICHARD D. KINDER)
KENNETH L. LAY * Director (KENNETH L. LAY)
EDWARD RANDALL, III * Director (EDWARD RANDALL, III)
*By /s/ ANGUS H. DAVIS (ANGUS H. DAVIS) (ATTORNEY-IN-FACT FOR PERSONS INDICATED)