Annual Report (Form 10-K), fiscal year 1994

ITEM 1. BUSINESS
GENERAL
Enron Oil & Gas Company (the "Company"), a Delaware corporation, is engaged, either directly or through a marketing subsidiary with regard to domestic operations or through various subsidiaries with regard to international operations, in the exploration for, and the development, production and marketing of, natural gas and crude oil primarily in major producing basins in the United States, as well as in Canada, Trinidad and India and to a lesser extent, selected other international areas. The Company's principal producing areas are further described under "Exploration and Production" below. At December 31, 1994, the Company's estimated net proved natural gas reserves were 1,910 billion cubic feet ("Bcf") and estimated net proved crude oil, condensate and natural gas liquids reserves were 37 million barrels ("MMBbl"). (See "Supplemental Information to Consolidated Financial Statements"). At such date, approximately 70% of the Company's reserves (on a natural gas equivalent basis) was located in the United States, 16% in Canada, 11% in Trinidad and 3% in India. As of December 31, 1994, the Company employed approximately 740 persons.
The Company pursues its oil and gas exploration and development operations primarily by the acquisition, through various means including but not limited to leasing, purchasing and farming-in of acreage that is either undeveloped or lightly developed, and drilling of internally generated prospects. The Company also maintains a strategy of selling selected oil and gas properties that for various reasons may no longer fit into future operational plans or are not assessed to have sufficient future growth potential, and when the economic value to be obtained by selling the properties and reserves in the ground is evaluated to be greater than what would be obtained by holding the properties and producing the reserves over time. As a result, the Company typically receives each year a varying but rather substantial level of proceeds related to such sales which proceeds are available for general corporate use.
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, and any reference to the ownership of interest or pursuit of operations in any international areas by the Company recognizes that all such interests are owned and operations are pursued by subsidiaries of Enron Oil & Gas Company. Unless the context otherwise requires, all references herein to Enron Corp. include Enron Corp., its predecessors and affiliates, other than the Company and its 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
NORTH AMERICAN OPERATIONS. The Company's six principal domestic producing areas are the Big Piney area, South Texas area, Matagorda Trend area, Canyon Trend area, Pitchfork Ranch area and Vernal area. Properties in these areas comprised approximately 76% of the Company's domestic reserves (on a natural gas equivalent basis) and 76% of the Company's maximum domestic net natural gas deliverability as of December 31, 1994 and are substantially all operated by the Company.
The Company's other domestic natural gas and crude oil producing properties are located primarily in other areas of Texas, Utah, New Mexico and Oklahoma.
At December 31, 1994, 93% of the Company's proved domestic reserves (on a natural gas equivalent basis) was natural gas and 7% was crude oil, condensate and natural gas liquids. A substantial portion of the Company's domestic 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 continued infill and other development drilling.
The Company also has natural gas and crude oil producing properties located in Western Canada, primarily in the provinces of Alberta, Saskatchewan and Manitoba.
BIG PINEY AREA. The Company's largest reserve accumulation is located in the Big Piney area in Sublette and Lincoln counties in southwestern Wyoming. The Company is the holder of the largest productive acreage base in this area, with approximately 219,000 net acres under lease directly within field limits. The Company operates approximately 650 natural gas wells in this area in which it owns a 91% average working interest. Deliveries from the area net to the Company averaged 124 million cubic feet ("MMcf") per day of natural gas and 1.5 thousand barrels ("MBbl") per day of crude oil, condensate, and natural gas liquids in 1994. At December 31, 1994, maximum natural gas deliverability net to the Company was approximately 142 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 67 wells in the Big Piney area in 1994 and anticipates an active drilling program will continue for several years. (See "Other Matters - Tight Gas Sand Tax Credits (Section 29) and Severance Tax Exemption").
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 470 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 250,000 net acres under lease in this area. Natural gas deliveries net to the Company averaged 181 MMcf per day in 1994. At December 31, 1994, maximum natural gas deliverability net to the Company was approximately 201 MMcf per day. The Company drilled 56 wells in the South Texas area in 1994 and anticipates an active drilling program will continue for several years. (See "Other Matters - Tight Gas Sand Tax Credits (Section 29) and Severance Tax Exemption").
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. In addition, the Company has extended its Matagorda Trend holdings into the Mustang Island area as a result of the purchase in 1994 of 15 OCS Blocks in the Matagorda and Mustang Island areas. The Company had a new field discovery at Mustang Island 759 in which it owns a 75% working interest and which is expected to commence deliveries in mid 1995 at a net rate of approximately 50 MMcf per day. The Company operates all of the offshore tracts mentioned above. Natural gas deliveries from these areas net to the Company averaged 65 MMcf per day in 1994. At December 31, 1994, maximum natural gas deliverability net to the Company from these blocks was approximately 85 MMcf per day.
CANYON TREND AREA. The Company's activities in this area have been concentrated in Crockett, Sutton, Terrell and Val Verde Counties, Texas where the Company drilled 331 natural gas wells during the period 1992 through 1994. During 1994, the Company increased its acreage position by
approximately 7,800 net acres to approximately 91,800 net acres and now operates approximately 500 natural gas wells in this area in which it owns a 97% average working interest. Production is from the Canyon sands and Strawn limestone at depths from 5,500 to 11,500 feet. In 1994, natural gas deliveries net to the Company averaged 65 MMcf per day and at December 31, 1994, maximum natural gas deliverability net to the Company was approximately 66 MMcf per day. The Company expects to maintain an active drilling program in the Canyon Trend area during 1995. (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 1994, deliveries net to the Company averaged 36 MMcf per day of natural gas and approximately 2 MBbl per day of crude oil, condensate and natural gas liquids. At December 31, 1994, maximum deliverability net to the Company was approximately 39 MMcf per day of natural gas and 3 MBbl per day of crude oil, condensate and natural gas liquids. During 1994, the Company increased crude oil, condensate and natural gas liquids reserves and deliverability through drilling. Additionally, the Company has increased its acreage position by approximately 12,300 net acres to approximately 27,900 net acres and expects to maintain an active drilling program in this field during 1995. (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 195 producing wells and presently controls approximately 79,000 net acres. In 1994, natural gas deliveries net to the Company from the Vernal area averaged 24 MMcf per day which is the maximum deliverability. 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 20 wells in the Vernal area in 1994 and expects to maintain a comparable drilling program during 1995. (See "Other Matters - Tight Gas Sand Tax Credits (Section 29) and Severance Tax Exemption").
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. The Company produces natural gas from seven major areas and crude oil from three major areas. The Sandhills area in Southern Saskatchewan is the largest single producing area where an additional 160 wells were drilled in 1994 resulting in deliverability net to the Company from the field of approximately 38 MMcf per day at December 31, 1994. Maximum Canadian natural gas deliverability net to the Company at December 31, 1994 was approximately 85 MMcf per day, and the Company held approximately 354,000 net undeveloped acres in Canada. The Company expects to maintain an active drilling program in Canada during 1995.
OUTSIDE NORTH AMERICA OPERATIONS. The Company has operations offshore Trinidad and India and is conducting exploration in selected other international areas. Properties offshore Trinidad and India comprised 100% of the Company's reserves and production outside of North America.
TRINIDAD. In November 1992, the Company was awarded a 95% working interest concession in the South East Coast Consortium Block offshore Trinidad, encompassing three undeveloped fields, previously held by three government-owned energy companies. The Kiskadee field is currently being developed while the remaining two undeveloped fields are anticipated to be developed 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, 1994, maximum natural gas deliverability net to the Company was approximately 150 MMcf per day and the Company held approximately 71,000 net undeveloped acres in Trinidad. Natural gas market takes were increased to approximately 121 MMcf per day and condensate deliveries were increased to approximately 5 MBbl per day, both net to the Company, as of January 1, 1995.
INDIA. In December 1994, the Company signed agreements covering profit sharing, joint operations and product sales and representing a 30% working interest in and was designated operator of the Tapti, Panna and Mukta Blocks located offshore Bombay, India. The blocks were previously operated by the Indian national oil company, Oil & Natural Gas Corporation Limited, which retains a 40% working interest. The 363,000 acre Tapti Block contains two major proved gas accumulations delineated by 22 expendable exploration wells that have been plugged. The Company plans to commence development of the Tapti Block accumulations immediately. The 106,000 acre Panna Block and the 192,000 acre Mukta Block are partially developed with five producing platforms located in the Panna and Mukta fields. The fields were producing approximately 3 MBbl per day of crude oil net to the Company as of December 31, 1994; all associated gas was being flared. The Company intends to continue development of the accumulations and to expand processing capacity to allow crude oil production at full deliverability as well as to permit natural gas sales.
OTHER INTERNATIONAL. The Company continues to pursue other selected conventional natural gas and crude oil opportunities outside North America. During 1995, 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. In early 1995, the Company and the Qatar General Petroleum Corporation signed a nonbinding letter of intent concerning the possible development of a liquefied natural gas project for natural gas to be produced from the North Dome Field. The Company and Enron Corp. may jointly hold up to a 40 percent working interest in the joint venture and would drill and develop the agreed upon reserves. In addition, the Company signed letters of intent in early 1995 with the National Oil Corporation of Uzbekistan, and Gazprom, the Russian Natural Gas Company, to pursue the feasibility of joint venture development and marketing of previously discovered hydrocarbon reserves in Uzbekistan.
The Company continues evaluation and assessment of its international opportunity portfolio in the coalbed methane recovery arena, including projects in South Wales in the U.K., the Lorraine Basin in France, Galilee Basin in Queensland, Australia and in two basins in China. A similar project in Russia continues under evaluation.
MARKETING
WELLHEAD MARKETING. The Company's North America wellhead natural gas production is currently being sold on the spot market and under long-term natural gas contracts at market responsive prices. In many instances, the long-term contract prices closely approximate the prices received for natural gas being sold on the spot market. Wellhead natural gas volumes from Trinidad are sold at prices that are based on a fixed price schedule with periodic escalations. Natural gas volumes in India will be sold to the Gas Authority of India, Ltd. under a take-or-pay contract at a price linked to a basket of world market fuel oil quotations with floor and ceiling limits. Approximately 45% 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 short and long-term agreements, natural gas to various purchasers and then aggregate the necessary supplies for the sales with purchases from various sources including third-party producers, marketing companies, pipelines or from the Company's own production. In addition, EOGM has purchased and constructed several small gathering systems in order to facilitate its entry into the gathering business on a limited basis. Both EOGM and the Company utilize other short and long-term hedging and trading mechanisms including sales and purchases utilizing NYMEX-related commodity market transactions. These marketing activities have
provided an effective balance in managing 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 in approximately 124 billion cubic feet equivalent ("Bcfe") (136 trillion British thermal units) of its natural gas and other hydrocarbon reserves. 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 various other areas for equivalent volumes produced by the Company and owned by the limited partnership under the terms of the volumetric production payment. 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, 1994:
YEAR ENDED DECEMBER 31, ------------------------------- 1994 1993 1992 --------- --------- --------- VOLUMES (PER DAY) Natural Gas (MMcf) United States(1)............. 614 649 534 Canada....................... 72 58 30 Trinidad..................... 63 2 - --------- --------- --------- Total(1)................... 749 709 564 ========= ========= ========= Crude Oil and Condensate (MBbl) United States................ 8.0 6.6 6.3 Canada....................... 2.0 2.2 2.2 Trinidad..................... 2.5 .1 - India........................ .1 - - --------- --------- --------- Total...................... 12.6 8.9 8.5 ========= ========= ========= Natural Gas Liquids (MBbl) United States................ .3 .2 .3 Canada....................... .4 .4 .4 --------- --------- --------- Total...................... .7 .6 .7 ========= ========= ========= AVERAGE PRICES Natural Gas ($/Mcf) United States(2)............. $ 1.71 $ 1.97 $ 1.61 Canada....................... 1.42 1.34 1.18 Trinidad..................... .93 .89 - Composite(2)............... 1.62 1.92 1.58 Crude Oil and Condensate ($/Bbl) United States................ $ 16.06 $ 16.96 $ 18.29 Canada....................... 14.05 14.63 16.80 Trinidad..................... 15.50 14.36 - India........................ 15.70 - - Composite.................. 15.62 16.37 17.90 Natural Gas Liquids ($/Bbl) United States................ $ 12.45 $ 13.85 $ 11.56 Canada....................... 8.45 9.46 10.05 Composite.................. 9.90 11.12 10.69 LEASE AND WELL EXPENSES ($/MCFE) United States................ $ .19 $ .18 $ .20 Canada....................... .34 .48 .50 Trinidad..................... .17 1.46 - India........................ .13 - - Composite.................. .20 .21 .22 - --------- (1) Includes 48 MMcf per day in 1994, 81 MMcf per day in 1993 and 28 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 $1.27 per Mcf in 1994, $1.57 per Mcf in 1993 and $1.70 Mcf in 1992 for the volumes described in note (1), net of transportation costs.
OTHER NATURAL GAS MARKETING VOLUMES AND PRICES
The following table sets forth certain information regarding the Company's volumes of natural gas delivered under other marketing and volumetric production payment arrangements, and resulting average per unit gross revenue and per unit amortization of deferred revenues along with associated costs during each of the three years in the period ended December 31, 1994. (See "Marketing" for a discussion of other natural gas marketing arrangements and agreements).
YEAR ENDED DECEMBER 31, ------------------------------- 1994 1993 1992 --------- --------- --------- Volumes (MMcf per day)(1)............ 324 293 255 Average Gross Revenue ($/Mcf)(2)..... $ 2.38 $ 2.57 $ 2.62 Associated Costs ($/Mcf)(3)(4)....... 2.06 2.32 1.99 --------- --------- --------- Margin ($/Mcf)....................... $ 0.32 $ 0.25 $ 0.63 ========= ========= ========= - --------- (1) Includes 48 MMcf per day in 1994, 81 MMcf per day in 1993 and 28 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 $2.46 per Mcf ($2.36 per million British thermal units) in 1994, $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 $1.92 per Mcf in 1994, $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 other world wide energy supplies including 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 liquid hydrocarbon resources through proration and restrictions on flaring, require drilling bonds and regulate environmental and safety matters. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its profitability.
A substantial portion of the Company's oil and gas leases in the Big Piney area and in the Gulf of Mexico, as well as some in other areas, are granted by the federal government and administered by the Bureau of Land Management (the "BLM") and the Minerals Management Service (the "MMS") federal agencies. Operations conducted by the Company on federal oil and gas leases must comply
with numerous statutory and regulatory restrictions concerning the above and other matters. Certain operations must be conducted pursuant to appropriate permits issued by the BLM and the MMS.
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. Commencing in April 1992, the FERC issued Order Nos. 636, 636-A and 636-B ("Order No. 636"), which mandate 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. As of early 1995, the FERC had issued final orders accepting most pipelines' Order No. 636 compliance filings and had commenced a series of one-year reviews of individual pipeline implementations of Order No. 636. Numerous parties have filed petitions for court review of Order No. 636 as well as orders in individual pipeline restructuring proceedings. Upon such judicial review, these orders may be amended or reversed in whole or in part. Order No. 636 does not directly regulate the Company's activities, but has had and will have an indirect effect because of its broad scope. With Order No. 636 and pending ongoing FERC reviews of individual pipeline restructurings, subject to court review, it is difficult to predict with precision its effects. In many instances, however, Order No. 636 has substantially reduced or brought to an end interstate pipelines' traditional roles as
wholesalers of natural gas in favor of providing only storage and transportation services. Order No. 636 has also substantially increased competition in natural gas markets, even though there remains significant uncertainty with respect to the marketing and transportation of natural gas. In spite of this uncertainty, Order No. 636 may enhance the Company's ability to market and transport its natural gas production, although it may also subject the Company to more restrictive pipeline imbalance tolerances and greater penalties for violation of such tolerances.
In 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. 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. In July 1994, the FERC eliminated a regulation that had rendered virtually all sales of natural gas by pipeline affiliates, such as the Company, to be deregulated first sales. As a result, only sales by the Company of its own production now qualify for this status. All other sales of gas by the Company, such as those of gas purchased from third parties, are now jurisdictional sales subject to the Order No. 547 certificate. The Company does not anticipate this change will have any significant current adverse effects in light of the flexible terms and conditions of the existing blanket certificate. Such sales are subject to the future possibility of greater federal oversight, however, including the possibility the FERC might prospectively impose more restrictive conditions on such sales.
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. In 1994, the Commission issued Order Nos. 566, 566-A and 566-B, in which it extended indefinitely its regulations (Order No. 497 regulations) governing relationships between interstate pipelines and their marketing affiliates, subject to revisions to delete an out-of-date standard and revise certain reporting and record keeping requirements. Among other matters, these new rules require pipelines to post on their electronic bulletin boards, within 24 hours of gas flow, information concerning discounted transportation provided to marketing affiliates to enable competing marketers to request comparable discounts. The rules retain existing standards, as revised by Order No. 497-E, requiring the contemporaneous disclosure to all shippers of transportation-related information provided a marketing affiliate, and prohibiting disclosure of certain information to marketing affiliates. 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 in 1993 enacted a prohibition against discriminatory gathering rates and recently announced plans to conduct an inquiry on alleged discriminatory practices by gatherers and transporters. In certain recent cases, the FERC has asserted ancillary NGA jurisdiction over gathering activities of interstate pipelines and their affiliates. In late 1993, the FERC convened a
conference to consider issues relating to gathering services performed by interstate pipelines or their affiliates. Commencing in May 1994, the FERC issued a series of orders in individual cases that delineate its gathering policy as a result of the comments received. Among other matters, the FERC slightly narrowed its statutory tests for establishing gathering status and reaffirmed that, except in situations in which the gatherer acts in concert with an interstate pipeline affiliate to frustrate the FERC's transportation policies, it does not have jurisdiction over natural gas gathering facilities and services and that such facilities and services are properly regulated by state authorities. This FERC action may further encourage regulatory scrutiny of natural gas gathering by state agencies. In addition, the FERC has approved several transfers by interstate pipelines, including certain of the Company's pipeline affiliates, of gathering facilities to unregulated independent or affiliated gathering companies. This could increase competition among gatherers in the affected areas. Certain of the FERC's orders delineating its new gathering policy are subject to pending court appeals. The Company's gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services.
The FERC has recently announced its intention to reexamine certain of its transportation-related policies, including the appropriate manner for setting rates for new interstate pipeline construction, the manner in which interstate pipelines release transportation capacity under Order No. 636, and the use of market-based rates for interstate gas transmission. While any resulting FERC action would affect the Company only indirectly, these inquiries are intended to further enhance competition in natural gas markets.
The Company's natural gas gathering operations may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement, and management of facilities. Pipeline safety issues have recently become the subject of increasing focus in various political and administrative arenas at both the state and federal levels. For example, federal legislation addressing pipeline safety issues was considered last year, which, if enacted, would have included a federal "one-call" notification system and certain new facilities specifications applicable to certain new construction. Similar "one call" legislation has been reintroduced in the U.S. Congress. The Company cannot predict what effect, if any, the adoption of this or other additional pipeline safety legislation might have on its operations, but does not believe that any adverse effect would be material.
The Company cannot predict the effect that any of the aforementioned orders or the challenges to such orders will ultimately have on the Company's operations. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC and the courts. The Company cannot predict when or whether any such proposals or proceedings may become effective. It should also be noted that the natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less regulated approach currently being pursued by the FERC will continue indefinitely. Thus, the Company cannot predict the ultimate outcome or durability of the unbundled regulatory regime mandated by Order No. 636.
ENVIRONMENTAL REGULATION. Various federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect the Company's operations and costs as a result of their effect on natural gas and crude oil exploration, development and production operations. It is not anticipated that the Company will be required in the near future to expend amounts that are material in relation to its total exploration and development expenditure program by reason of environmental laws and regulations, but inasmuch as such laws and regulations are frequently changed, the Company is unable to predict the ultimate cost of compliance.
CANADIAN REGULATION. In Canada, the petroleum industry operates under Federal, provincial and municipal legislation and regulations governing land tenure, royalties, production rates, pricing, environmental 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.
INTERNATIONAL REGULATION. The Company's exploration and production operations outside North America are subject to various types of regulations imposed by the respective governments of the countries in which the Company's operations are conducted, and may affect the Company's operations and costs within that country. The Company currently has operations offshore Trinidad and India and exploration activities in other selected international areas.
RELATIONSHIP BETWEEN THE COMPANY AND ENRON CORP.
OWNERSHIP OF COMMON STOCK. Enron Corp. owns 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 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 1994, pursuant to which Enron Corp. provides various services, such as maintenance of certain employee benefit plans, provision of telecommunications and computer services, lease of office space and the provision of purchasing and operating services and certain other corporate staff and support services. Such services historically have been supplied to the Company by Enron Corp., and the Services Agreement provides for the further delivery of such services substantially identical in nature and quality to those services previously provided. The Company has agreed to a fixed rate for the rental of office space and to reimburse Enron Corp. for all other direct costs incurred in rendering services to the Company under the contract and to pay Enron Corp. for allocated indirect costs incurred in rendering such services up to a maximum of $6.7 million for 1994, such cap to be increased in subsequent years for inflation and certain changes in the Company's allocation bases with any increase not to exceed 7.5% per year. The Services Agreement is for an initial term of five years through December 1998 and will continue thereafter until terminated by either party.
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.
The Company has 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.
Circumstances may also arise that would cause Enron Corp. to engage in the exploration for and/or development and production of natural gas and crude oil in competition with the Company. For example, opportunities might arise which would require financial resources greater than those available to the Company, which are located in areas or countries in which the Company does not intend to operate or which involve properties that the Company would be unwilling to acquire. Also, Enron Corp. might acquire a competing 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 or capital, Enron Corp. may from time to time acquire producing properties or interests in entities owning producing properties, and thereafter engage in exploration, development and production activities with respect to such properties or indirectly engage in such activities through such companies. Enron Corp. may also acquire interests in oil and gas properties or companies in connection with its financing activities. For example, in its financing activities Enron Corp. or an entity in which it has an interest may make loans secured by oil and gas properties or securities of oil and gas companies, may acquire production payments or may receive interests in oil and gas properties as equity components of lending tranactions. As a result of its lending activities, Enron Corp. may also acquire oil and gas properties or companies upon foreclosure of secured loans or as part of a borrower's rearrangement of its obligations. Such acquisition, exploration, development and production activities may directly or indirectly compete with the Company's business. Thus, there can be no assurances that Enron Corp. will not engage directly or indirectly through entities other than the Company, in the natural gas and crude oil exploration, development and production business in competition with the Company.
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, domestic 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, technology developments, weather and other international energy supplies over which the Company has no control.
Average North America wellhead natural gas prices have fluctuated, at times rather dramatically, during the last three years. While these fluctuations resulted in increases in average wellhead natural gas prices realized by the Company of 15% from 1991 to 1992 and 22% from 1992 to 1993, the average North America natural gas price received by the Company decreased 13% from 1993 to 1994. Wellhead natural gas volumes from Trinidad are sold at prices that are based on a fixed schedule of periodic escalations. While natural gas deliveries in India are not expected to commence until 1996, the price of such deliveries, when initiated, will be indexed to a basket of world market fuel oil quotations structured to include floor and ceiling limits. Due to the many uncertainties associated with the world political environment, the availabilities of other world wide energy supplies and the relative competitive relationships of the various energy sources in the view of the consumers, the Company is unable to predict what changes may occur in natural gas prices in the future.
Substantially all of the Company's wellhead crude oil and condensate is sold under short-term contracts at market responsive prices. 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, 9% from 1992 to 1993 and 5% from 1993 to 1994. Due to the many uncertainties associated with the world political environment, the availabilities of other world wide energy supplies and the relative competitive relationships of the various energy sources in the view of the consumers, the Company is unable to predict what changes may occur in crude oil and condensate prices in the future.
To mitigate the risk of market price fluctuations, the Company engages in certain price risk management activities to hedge commodity prices associated with the sales and purchases of natural gas and crude oil.
TIGHT GAS SAND TAX CREDITS (SECTION 29) AND SEVERANCE TAX EXEMPTION. Federal United States 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 $44 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 operations outside of North America are subject to certain risks, including expropriation of assets, risks of increases in taxes and government royalties, renegotiation of contracts with foreign governments, political instability, payment delays, limits on allowable levels of production and current exchange and repatriation losses, as well as changes in laws, regulations and policies governing operations of foreign companies generally.
CURRENT EXECUTIVE OFFICERS OF THE REGISTRANT
The current executive officers of the Company and their names and ages are as follows:
NAME AGE POSITION ---- --- -------- Forrest E. Hoglund................. 61 Chairman of the Board, President and Chief Executive Officer; Director Joe Michael McKinney............... 55 President-International Operations Mark G. Papa....................... 48 President-North American Operations George E. Uthlaut.................. 61 Senior Vice President-Operations Walter C. Wilson................... 52 Senior Vice President and Chief Financial Officer Ben B. Boyd........................ 53 Vice President and Controller Dennis M. Ulak..................... 41 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 Oil & Gas International, Inc., 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 Oil & Gas International, Inc. 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, 1994. 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 390 fields and oil wells in 87 fields located in Texas, offshore Texas and Louisiana in the Gulf of Mexico, Oklahoma, New Mexico, Utah, Wyoming, and various other states, Canada, Trinidad and India at December 31, 1994. Gross oil and gas wells include 188 with multiple completions.
PRODUCTIVE WELLS --------------------- GROSS NET ------ ------ Gas.................................. 4,501 3,246 Oil.................................. 933 564 ------ ------ Total............................ 5,434 3,810 ====== ======
DRILLING AND ACQUISITION ACTIVITIES. During the years ended December 31, 1994, 1993 and 1992 the Company spent approximately $493.9, $430.1 and $395.7 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. On April 6, 1994, Enron Corp. was granted summary judgement, wherein the court ordered that TransAmerican can take nothing on its claims against Enron Corp. Trial, which was set most recently for September 12, 1994 has been continued, and there is no current setting. 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 1994.
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 of the Company, as reported on the New York Stock Exchange Composite Tape, and the amount of cash dividends paid per share. The 1992, 1993, and First Quarter and Second Quarter 1994 sales prices and cash dividends per share have been restated to reflect the two-for-one stock split declared in May 1994 by the Board of Directors. Shares were issued on June 15, 1994 to shareholders of record as of May 31, 1994.
PRICE RANGE -------------------- CASH HIGH LOW DIVIDENDS --------- --------- --------- First Quarter.................... 10.94 8.31 .025 Second Quarter................... 13.63 10.25 .025 Third Quarter.................... 17.94 12.69 .025 Fourth Quarter................... 17.19 13.75 .025 First Quarter.................... 20.31 13.38 .030 Second Quarter................... 22.50 17.88 .030 Third Quarter.................... 26.81 19.88 .030 Fourth Quarter................... 27.00 17.06 .030 First Quarter.................... 23.75 19.31 .030 Second Quarter................... 24.63 22.38 .030 Third Quarter.................... 23.00 18.50 .030 Fourth Quarter................... 22.75 17.38 .030
As of March 2, 1995, there were approximately 291 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 $0.025 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 $0.03 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, 1994 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, ------------------------------- 1994 1993 1992 --------- --------- --------- Wellhead Volumes Natural Gas (MMcf per day)(1).... 749 709 564 Crude Oil and Condensate (MBbl per day)....................... 12.6 8.9 8.5 Natural Gas Liquids (MBbl per day)........................... 0.7 0.6 0.7 Wellhead Average Prices Natural Gas ($/Mcf)(2)........... $ 1.62 $ 1.92 $ 1.58 Crude Oil and Condensate ($/Bbl)........................ 15.62 16.37 17.90 Natural Gas Liquids ($/Bbl)...... 9.90 11.12 10.69 Other Natural Gas Marketing Volumes (MMcf per day)(1)........ 324 293 255 Average Gross Revenue ($/Mcf)(3)..................... $ 2.38 $ 2.57 $ 2.62 Associated Costs ($/Mcf) (4)(5)................. 2.06 2.32 1.99 --------- --------- --------- Margin ($/Mcf)................... $ 0.32 $ 0.25 $ 0.63 ========= ========= ========= - --------- (1) Includes 48 MMcf per day in 1994, 81 MMcf per day in 1993 and 28 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 $1.27 per Mcf in 1994, $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 $2.46 per Mcf ($2.36 per million British thermal units) in 1994, $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 $1.92 per Mcf in 1994, $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 1994, net operating revenues increased to $626 million, up $45 million as compared to 1993.
Average wellhead natural gas volumes increased approximately 6% compared to 1993 primarily reflecting the effects of development activities in Trinidad and Canada partially offset by voluntary curtailments of production in the United States in 1994. The volume reductions in the United States as a result of voluntary curtailments were more than offset by the new natural gas deliveries from the Kiskadee field offshore Trinidad and increased deliveries in Canada. The increase in wellhead natural gas volumes added $28 million to net operating revenues. Average wellhead natural gas prices were down significantly from 1993 reducing net operating revenues by approximately $83 million. This 16% reduction in average wellhead natural gas prices reflects the overall decline in the United States natural gas markets during the last half of 1994 and increased volumes from Trinidad sold under a long-term contract at a price considerably below North American spot market prices. A 42% increase in wellhead crude oil and condensate volumes over 1993 added $22 million to net operating revenues primarily reflecting development activities in Trinidad and increased production in the United States. A 5% decrease in wellhead crude oil and condensate average prices decreased net operating revenues by approximately $3 million.
Other marketing activities associated with sales and purchases of natural gas, natural gas and crude oil price swap transactions, other commodity price hedging of natural gas and crude oil prices utilizing NYMEX-related commodity market transactions, and margins relating to the volumetric production payment added $50 million to net operating revenues during 1994. This increase of $42 million from the same period in 1993 primarily results from a gain of $11 million on natural gas commodity price hedging activities utilizing NYMEX-related commodity market transactions in 1994 versus an $18 million loss during 1993 and increased margins associated with other natural gas marketing activities. 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, decreased $.26 per Mcf. The average price received for these transactions decreased $.19 per Mcf. Related other natural gas marketing volumes increased 10%.
The impact of 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 increases or reductions in revenues associated with market responsive prices for wellhead deliveries. (See Note 2 to Consolidated Financial Statements.)
Gains on sales of selected oil and gas reserves and related assets were $54 million in 1994 as compared to $13 million in 1993. While the quantity of equivalent reserves sold in 1994 was slightly less than 1993, higher average proceeds received per equivalent unit in 1994 as compared to 1993 primarily contributed to the increased gain recognition. In continuing its strategy of fully utilizing its assets in optimizing profitability, cash flow and return on investments, the Company expects to continue the sale of similar properties from time to time.
During 1993, net operating revenues increased to $581 million, up $122 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 NYMEX-related commodity 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-related 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%.
OPERATING EXPENSES. During 1994, total operating expenses of $466 million were approximately $1 million higher than the $465 million incurred in 1993. Lease and well expenses of $60 million were approximately $1 million higher than last year primarily due to increased expenses related to new operations offshore Trinidad partially offset by cost reductions in North America. Exploration expenses of $42 million increased $5 million from the previous year primarily due to an increased level of exploration activities. Impairment of unproved oil and gas properties increased $4 million from 1993 primarily due to impairments associated with certain offshore Gulf of Mexico leases. Depreciation, depletion and amortization ("DD&A") expense decreased from $250 million in 1993 to $242 million in 1994 reflecting a $.09 per Mcfe decrease in the average DD&A rate to $.80 per Mcfe. The rate decrease is primarily due to increased production from offshore Trinidad at an average DD&A rate significantly less than the North American operations DD&A rate and a $.03 per Mcfe reduction in the North American operations DD&A rate. General and administrative expenses increased $6 million to $51 million primarily due to overall higher costs associated with expanded international and domestic operations. Taxes other than income decreased approximately $7 million from 1993 primarily due to lower taxable United States wellhead volumes and prices and reductions included in 1994 related to revisions of certain prior year production taxes. Included in 1994 and 1993 are benefits associated with reductions in state franchise taxes of $4 million and $3 million, respectively. The Company continues to benefit from certain state severance tax exemptions allowed on high cost natural gas volumes.
Total per unit operating costs for lease and well expense, DD&A, general and administrative expense, interest expense, and taxes other than income decreased $.14 per Mcfe, averaging $1.29 per Mcfe during 1994 compared to $1.43 per Mcfe for 1993. The decrease was primarily due to per unit reductions in DD&A and taxes other than income as discussed above.
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. An unsuccessful Gulf of Mexico 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. 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 volumes 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.
OTHER INCOME. Other income for 1993 includes $4 million in interest income associated with the investment of funds temporarily surplus to the Company (See Note 4 to Consolidated Financial Statements) and $4 million associated with settlements related to the termination of certain long-term natural gas contracts.
INTEREST EXPENSE. Net interest expense in 1994 decreased approximately $1 million to $8 million as compared to 1993 primarily due to favorable interest rates on new financing acquired by a subsidiary of the Company in Trinidad and the retirement of higher interest rate debt. The estimated fair value of outstanding interest rate swap agreements at December 31, 1994 was a negative $0.5 million based on termination values obtained from third parties. (See Note 13 to Consolidated Financial Statements).
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.
INCOME TAXES. Income tax provision in 1994 includes a benefit of approximately $36 million associated with tight gas sand federal income tax credit utilization, a benefit of approximately $8 million related to reduced estimated state income taxes and a portion of certain franchise taxes which is treated as income tax under SFAS No. 109, and a $5 million benefit from the reduction of the Company's deferred federal income tax liability resulting from a reevaluation of deferred tax requirements.
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 deferred federal income tax liability resulting from a reevaluation of deferred tax requirements.
CAPITAL RESOURCES AND LIQUIDITY
CASH FLOW. The primary sources of cash for the Company during the three-year period ended December 31, 1994 included funds generated from operations, the sale of common stock, the sale of a volumetric production payment, proceeds from the sale of selected oil and gas reserves and related assets and the issuance of new debt. 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, gains on sales of oil and gas reserves and related assets, certain other miscellaneous non-cash amounts, except for amortization of deferred revenue, and exploration and dry hole expenses. However, based on the continuing practice of the Company of selling selected oil and gas reserves and related assets in furtherance of its strategy of fully utilizing its assets in optimizing profitability, cash flow and return on investments, it believes that net proceeds from these transactions should also be considered as available discretionary cash flow and is so presenting those values for 1994. Values for prior years have also been reclassified for consistency. 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 $514 million in 1994, $521 million in 1993 and $346 million in 1992. 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 $426 million in 1994, $480 million in 1993 and $306 million in 1992. Decreased 1994 net operating cash flows were primarily due to proceeds in 1993 from the receipt of a refund on settlement of an audit of federal income taxes discussed above. 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. In accordance with the requirements of SFAS No. 95 - "Statement of Cash Flows", net proceeds from the sale of selected oil and gas reserves and related assets are not included in the determination of cash from operations.
SALE OF SELECTED OIL AND GAS RESERVES AND RELATED ASSETS. During 1994, the Company received proceeds of $91 million from the sale of selected oil and gas reserves and related assets compared to $42 million received in 1993. While the quantity of equivalent reserves sold in 1994 was slightly less than 1993, higher average proceeds received per equivalent unit of reserves sold in 1994 as compared to 1993 resulted in significantly higher 1994 proceeds. Taxable gains resulting from the 1994 sales generated income taxes of $20 million, leaving net proceeds of $71 million. Taxable gains resulting from the 1993 sales generated federal income taxes of $8 million, leaving net proceeds of $34 million.
SALE OF VOLUMETRIC PRODUCTION PAYMENT. In September 1992, the Company sold a volumetric production payment for $326.8 million to a limited partnership. (See "Business - Marketing - Other Marketing" and Note 5 to Consolidated Financial Statements). Under the terms of the production payment agreements, the Company conveyed a real property interest in approximately 124 Bcfe (136 trillion British thermal units) of certain natural gas and other hydrocarbons to the purchaser. Effective October 1, 1993, the agreements were amended providing for the extension of the original term of the volumetric production payment through March 31, 1999 and including a revised schedule of daily quantities of hydrocarbons to be delivered which is approximately one-half of the original schedule. The revised schedule will total approximately 89.1 Bcfe (97.8 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. 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, 1994, 1993 and 1992, along with those budgeted for the year 1995.
ACTUAL ------------------------------- BUDGETED EXPENDITURE CATEGORY 1994 1993 1992 1995 - -------------------- --------- --------- --------- -------
(IN MILLIONS) Capital Drilling and Facilities......... $ 342 $ 331 $ 260 $ 345 Leasehold Acquisitions.......... 52 29 23 25 Producing Property Acquisitions.................. 34 9 65 15 Capitalized Interest and Other.. 14 14 14 15 --------- --------- --------- ------- Total....................... 442 383 362 400 Exploration Expenses................ 59 55 44 50 --------- --------- --------- ------- Total............................... $ 501 $ 438 $ 406 $ 450 ========= ========= ========= =======
Exploration and development expenditures increased $63 million, or 14%, in 1994 compared to 1993. The increase primarily reflects the acquisitions of selected properties to compliment existing North American producing areas and the addition of new international activities in India. (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 1995 exploration and development expenditure plans).
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 1993, the Company installed a jacket, platform and production facilities and initiated natural gas production from the Kiskadee field offshore the southeast coast of Trinidad.
FINANCING. The Company's long-term debt-to-total-capital ratio was 15% and 14% as of December 31, 1994 and 1993, 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 1994, 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 may advance 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 $69 million during 1994 with no balance outstanding at December 31, 1994. There was a balance of $7 million outstanding at December 31, 1994 under a commercial paper program initiated in 1990. Proceeds from the commercial paper program were used to fund current transactions. During 1994, total long-term debt increased $37 million to $190 million as a result of $23 million of new borrowings related to certain international drilling activities, a $7 million increase in commercial paper, and the recording of a $7 million capital lease obligation. (See Note 4 to the Consolidated Financial Statements). The estimated fair value of the Company's long-term debt, including current maturities of $2 million and $30 million, at December 31, 1994 and 1993 was $186 million and $192 million, respectively, based upon quoted market prices and, where such prices were not available, upon interest rates currently available to the Company at year end. (See Note 13 to the Consolidated Financial Statements).
OUTLOOK. There continues to exist a good deal of uncertainty as to the direction of future North America natural gas price trends and a rather wide divergence in the opinions held by some in the industry. However, recent history would tend to support, and it seems there is emerging among a larger number of industry representatives somewhat of a consensus, that natural gas prices will remain below parity with crude oil, condensate and natural gas liquids for some time. This situation is being impacted by improvements in the technology used in drilling and completing oil and gas
wells that are tending to mitigate the impacts of fewer oil and gas wells being drilled, the deregulation of the natural gas market under Federal Energy Regulatory Commission Order 636 and subsequent related orders, and improvements being realized in the availability and utilization of natural gas storage capacity. However, the continually increasing recognition of natural gas as a more environmentally friendly source of energy along with the availability of significant domestically sourced supplies should result in further increases in demand and a supporting/strengthening of the overall natural gas market over time. Being primarily a natural gas producer, the Company is more significantly impacted by changes in natural gas prices than by changes in crude oil and condensate prices. (See "Business - Other Matters - Energy Prices"). Based on the portion of the Company's anticipated natural gas volumes for which prices have not, in effect, been hedged using NYMEX-related commodity market transactions, long-term marketing contracts and the sale of a volumetric production payment, the Company's net income and cash flow sensitivity to changing natural gas prices is approximately $10 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 one-half of its anticipated wellhead natural gas volumes and about one-third of its anticipated wellhead crude oil and condensate volumes for the year 1995 and about one-third of its anticipated wellhead natural gas volumes and about one-sixth of its anticipated wellhead crude oil and condensate volumes for the year 1996. The percentage of volumes hedged may change during the remainder of 1995 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 1994, 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 $36 million in 1994 and is estimated to be approximately $21 million for 1995, 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 qualifying 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 1994. (See "Business - Other Matters - - Tight Gas Sand Tax Credit (Section 29) and Severance Tax Exemption"). Other natural gas marketing activities are also expected to continue to contribute meaningfully to financial results. The 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 5 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 plans to continue to focus a substantial portion of its development and certain exploration expenditures in its major producing areas in North America. However, based on the continuing uncertainty associated with North America natural gas prices and the current weakness in that market, and as a result of the recent success realized in Trinidad and opportunities available to the Company in conjunction with the recent signing of agreements in India, the Company anticipates expending an increasing portion of its available funds in the further development of these opportunities. In addition, the Company expects to include limited but meaningful exploratory exposure in other areas outside of North America in its expenditure plans. (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 North America 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. The continuation of expenditures in other areas outside of North America, will be primarily for additional evaluation of coalbed methane recovery potential in the U.K., France, Australia, China, Russia and certain other countries.
The level of exploration and development expenditures may vary in 1995 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 1995 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. While the Company has certain continuing commitments associated with expenditure plans related to operations in India, they are not anticipated to be material when considered in relation to the total financial capacity of the Company.
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 "Certain Transactions", and is incorporated herein by reference.
PART IV
ITEM 14.

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULE, AND REPORTS ON FORM 8-K
(a)(1) AND (2) FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULE
See "Index to Financial Statements" set forth on page.
(a)(3) EXHIBITS
See pages E-1 through E-5 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 1994.
ENRON OIL & GAS COMPANY PAGE ---- Consolidated Financial Statements:
Management's Responsibility for Financial Reporting....
Reports of Independent Public Accountants..............
Consolidated Statements of Income for Each of the Three Years in the Period Ended December 31, 1994....
Consolidated Balance Sheets - December 31, 1994 and 1993.............................................
Consolidated Statements of Shareholders' Equity for Each of the Three Years in the Period Ended December 31, 1994..............................
Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 1994....
Notes to Consolidated Financial Statements.............
Supplemental Information to Consolidated Financial Statements...............................................
Financial Statement Schedule:
Schedule II - Valuation and Qualifying Accounts and Reserves......................................... S-1
Other financial statement schedules have been omitted because they are inapplicable or the information required therein is included elsewhere in the consolidated financial statements or notes thereto.
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 LLP, independent public accountants, was engaged to audit the consolidated financial statements of Enron Oil & Gas Company and its subsidiaries and issue a report thereon. In the conduct of the audit, Arthur Andersen LLP was given unrestricted access to all financial records and related data including minutes of all meetings of shareholders, the Board of Directors and committees of the Board. Management believes that all representations made to Arthur Andersen LLP during the audit were valid and appropriate. Their audits of the years presented included developing an overall understanding of the Company's accounting systems, procedures and internal controls, and conducting tests and other auditing procedures sufficient to support their opinion on the financial statements. Arthur Andersen LLP was also engaged to examine and report on management's assertion about the effectiveness of the system of internal controls of Enron Oil & Gas Company and its subsidiaries. The reports of Arthur Andersen LLP appear on the following page.
The system of internal controls of Enron Oil & Gas Company and its subsidiaries is designed to provide reasonable assurance as to the reliability of financial statements and the protection of assets from unauthorized acquisition, use or disposition. This system includes, but is not limited to, written policies and guidelines including a published code for the conduct of business affairs, conflicts of interest and compliance with laws regarding antitrust, anti-boycott and foreign corrupt practices policies, the careful selection and training of qualified personnel, and a documented organizational structure outlining the separation of responsibilities among management representatives and staff groups.
The adequacy of financial controls of Enron Oil & Gas Company and its subsidiaries and the accounting principles employed in financial reporting by the Company are under the general oversight of the Audit Committee of the Board of Directors. No member of this committee is an officer or employee of the Company. The independent public accountants have direct access to the Audit Committee and meet with the committee from time to time to discuss accounting, auditing and financial reporting matters.
It should be recognized that there are inherent limitations to the effectiveness of any system of internal control, including the possibility of human error and circumvention or override. Accordingly, even an effective system can provide only reasonable assurance with respect to the preparation of reliable financial statements and safeguarding of assets. Furthermore, the effectiveness of an internal control system can change with circumstances.
It is management's opinion that, considering the criteria for effective internal control over financial reporting and safeguarding of assets which consists of interrelated components including the control environment, risk-assessment process, control activities, information and communication systems, and monitoring, the Company maintained an effective system of internal control as to the reliability of financial statements and the protection of assets against unauthorized acquisition, use or disposition for 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 February 17, 1995
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Enron Oil & Gas Company:
We have examined management's assertion that the system of internal control of Enron Oil & Gas Company and its subsidiaries for the year ended December 31, 1994, was adequate to provide reasonable assurance as to the reliability of financial statements and the protection of assets against unauthorized acquisition, use or disposition, included in the accompanying report on Management's Responsibility for Financial Reporting.
Our examination was made in accordance with standards established by the American Institute of Certified Public Accountants and, accordingly, included obtaining an understanding of the system of internal control, testing and evaluating the design and operating effectiveness of the system of internal control, and such other procedures as we considered necessary in the circumstances. We believe that our examination provides a reasonable basis for our opinion.
Because of inherent limitations in any system of internal control, errors or irregularities may occur and not be detected. Also, projections of any evaluation of the system of internal control to future periods are subject to the risk that the system of internal control may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management's assertion that the system of internal control of Enron Oil & Gas Company and its subsidiaries for the year ended December 31, 1994, was adequate to provide reasonable assurance as to the reliability of financial statements and the protection of assets against unauthorized acquisition, use or disposition is fairly stated in all material respects, based upon the control criteria therein.
ARTHUR ANDERSEN LLP Houston, Texas February 17, 1995
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, 1994 and 1993, and the related consolidated statements of income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 1994. These financial statements and the schedule referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and the schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Enron Oil & Gas Company and subsidiaries as of December 31, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The financial statement schedule listed in the index to financial statements is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP Houston, Texas February 17, 1995
ENRON OIL & GAS COMPANY CONSOLIDATED STATEMENTS OF INCOME (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31, ------------------------------------- 1994 1993 1992 ----------- ----------- ----------- NET OPERATING REVENUES Natural Gas Associated Companies........... $ 267,997 $ 279,921 $ 280,501 Trade.......................... 221,896 225,241 108,487 Crude Oil, Condensate and Natural Gas Liquids Associated Companies........... 46,782 38,953 38,775 Trade.......................... 29,556 16,881 20,152 Gains on Sales of Reserves and Related Assets.................. 54,014 13,318 6,037 Other............................. 5,578 6,706 5,074 ----------- ----------- ----------- Total.................... 625,823 581,020 459,026 OPERATING EXPENSES Lease and Well.................... 60,384 59,344 49,406 Exploration....................... 41,811 36,921 33,278 Dry Hole.......................... 17,197 18,355 10,764 Impairment of Unproved Oil and Gas Properties...................... 24,936 20,467 15,136 Depreciation, Depletion and Amortization.................... 242,182 249,704 179,839 General and Administrative........ 51,418 45,274 36,648 Taxes Other Than Income........... 28,254 35,396 28,346 ----------- ----------- ----------- Total.................... 466,182 465,461 353,417 ----------- ----------- ----------- OPERATING INCOME..................... 159,641 115,559 105,609 OTHER INCOME (EXPENSE)............... 2,783 6,635 (3,476) ----------- ----------- ----------- INCOME BEFORE INTEREST EXPENSE AND TAXES.............................. 162,424 122,194 102,133 INTEREST EXPENSE Incurred Affiliate...................... 629 - 1,747 Other.......................... 13,984 15,378 24,122 Capitalized....................... (6,124) (5,457) (3,580) ----------- ----------- ----------- Net Interest Expense........... 8,489 9,921 22,289 ----------- ----------- ----------- INCOME BEFORE INCOME TAXES........... 153,935 112,273 79,844 INCOME TAX PROVISION (BENEFIT)....... 5,937 (25,752) (17,736) ----------- ----------- ----------- NET INCOME........................... $ 147,998 $ 138,025 $ 97,580 =========== =========== =========== EARNINGS PER SHARE OF COMMON STOCK... $ .93 $ .86 $ .63 =========== =========== =========== AVERAGE NUMBER OF COMMON SHARES...... 159,845 159,966 154,533 =========== =========== ===========
The accompanying notes are an integral part of these consolidated financial statements.
ENRON OIL & GAS COMPANY CONSOLIDATED BALANCE SHEETS (IN THOUSANDS)
AT DECEMBER 31, ---------------------------- 1994 1993 ------------- ------------- ASSETS CURRENT ASSETS Cash and Cash Equivalents......... $ 5,810 $ 103,129 Accounts Receivable Associated Companies........... 57,352 59,143 Trade.......................... 68,781 66,109 Inventories....................... 15,731 14,082 Other............................. 8,744 6,962 ------------- ------------- Total....................... 156,418 249,425 OIL AND GAS PROPERTIES (Successful Efforts Method)...................... 3,015,435 2,772,220 Less: Accumulated Depreciation, Depletion and Amortization...... 1,330,624 1,226,175 ------------- ------------- Net Oil and Gas Properties................ 1,684,811 1,546,045 OTHER ASSETS......................... 20,638 15,692 ------------- ------------- TOTAL ASSETS......................... $ 1,861,867 $ 1,811,162 ============= =============
LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Accounts Payable Associated Companies........... $ 13,353 $ 13,250 Trade.......................... 117,791 143,542 Accrued Taxes Payable............. 17,631 17,354 Dividends Payable................. 4,800 4,795 Current Maturities of Long-Term Debt............................ 1,718 30,000 Other............................. 9,308 8,989 ------------- ------------- Total....................... 164,601 217,930 LONG-TERM DEBT Affiliate......................... 25,000 - Other............................. 165,337 153,000 OTHER LIABILITIES.................... 10,035 9,477 DEFERRED INCOME TAXES................ 269,292 270,154 DEFERRED REVENUE..................... 184,183 227,528 COMMITMENTS AND CONTINGENCIES (Note 9) SHAREHOLDERS' EQUITY Common Stock, $.01 Par, 160,000,000 Shares Authorized and Issued at December 31, 1994 and No Par, 160,000,000 Shares Authorized and Issued at December 31, 1993............... 201,600 200,800 Additional Paid In Capital........ 403,488 417,531 Cumulative Foreign Currency Translation Adjustment.......... (15,298) (6,855) Retained Earnings................. 453,810 324,995 Common Stock Held in Treasury, 9,173 shares at December 31, 1994 and 160,000 shares at December 31, 1993............... (181) (3,398) ------------- ------------- Total Shareholders' Equity...................... 1,043,419 933,073 ------------- ------------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY............................. $ 1,861,867 $ 1,811,162 ============= =============
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)
The accompanying notes are an integral part of these consolidated financial statements.
ENRON OIL & GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
YEAR ENDED DECEMBER 31, ------------------------------------- 1994 1993 1992 --------- --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES Reconciliation of Net Income to Net Operating Cash Inflows: Net Income........................ $ 147,998 $ 138,025 $ 97,580 Items Not Requiring (Providing) Cash Depreciation, Depletion and Amortization................. 242,182 249,704 179,839 Impairment of Unproved Oil and Gas Properties............... 24,936 20,467 15,136 Deferred Income Taxes.......... 1,788 25,612 (17,917) Other, Net..................... (2,735) 1,768 5,713 Exploration Expenses.............. 41,811 36,921 33,278 Dry Hole Expenses................. 17,197 18,355 10,764 Gains On Sales of Reserves and Related Assets.................. (54,014) (13,318) (6,037) Other, Net........................ 4,490 1,242 (6,147) Changes in Components of Working Capital and Other Liabilities Accounts Receivable............ (883) (24,586) (12,732) Inventories.................... (2,163) (4,548) 3,687 Accounts Payable............... (25,648) 26,208 46,327 Accrued Taxes Payable.......... 277 7,443 247 Other Liabilities.............. 1,086 772 (2,886) Other, Net..................... (1,463) (44,443) 33,784 Changes in Components of Working Capital Associated with Investing and Financing Activities...................... 31,038 40,042 (74,232) --------- --------- --------- NET OPERATING CASH INFLOWS........... 425,897 479,664 306,404 INVESTING CASH FLOWS Additions to Oil and Gas Properties...................... (442,078) (383,064) (362,403) Exploration Expenses.............. (41,811) (36,921) (33,278) Dry Hole Expenses................. (17,197) (18,355) (10,764) Proceeds from Sales of Reserves and Related Assets (Note 10).... 90,515 41,815 33,412 Proceeds from Sale of Volumetric Production Payment.............. - -} 326,775 Amortization of Deferred Revenue......................... (43,345) (73,867) (25,380) Changes in Components of Working Capital Associated with Investing Activities............ (32,120) (37,256) 74,232 Other, Net........................ (8,758) (4,905) (3,686) --------- --------- --------- NET INVESTING CASH OUTFLOWS.......... (494,794) (512,553) (1,092) FINANCING CASH FLOWS Long-Term Debt Affiliate...................... 25,000 - (132,836) Other.......................... (25,300) 33,000 (139,556) Common Stock Issued............... - - 111,861 Dividends Paid.................... (19,178) (19,200) (15,385) Treasury Stock Purchased.......... (14,139) (16,698) (1,827) Proceeds from Sales of Treasury Stock........................... 4,113 9,084 1,250 Other, Net........................ 1,082 (2,786) - --------- --------- --------- NET FINANCING CASH INFLOWS (OUTFLOWS)......................... (28,422) 3,400 (176,493) --------- --------- --------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........................ (97,319) (29,489) 128,819 CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR.................. 103,129 132,618 3,799 --------- --------- --------- CASH AND CASH EQUIVALENTS AT END OF YEAR............................... $ 5,810 $ 103,129 $ 132,618 ========= ========= =========
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 4 "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. Amortization of any remaining costs of such leases begins at a point prior to the end of the lease term depending upon the length of such term. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience, is amortized over the average holding period. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred.
Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. The costs of all development wells and related equipment used in the production of 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.
Based on the Company's strategy of maximizing the economic value of its assets through a combination of both developing and producing over time, crude oil and natural gas reserves and the sale of such reserves in place with related assets; effective for 1994, gains and losses associated with such sales in place are being classified as Net Operating Revenues in the consolidated statements of income.
ACCOUNTING FOR INTEREST AND PRICE RISK MANAGEMENT The Company engages in price and interest rate risk management activities for primarily non-trading purposes. Such activities consist of transactions to hedge commodity prices associated with the sales and purchases of natural gas and crude oil in order to mitigate the risk of market price fluctuations and interest rate swap agreements to effectively convert portions of floating rate debt to a fixed rate basis, thereby reducing the impact of interest rate changes on future income. Changes in the market value of commodity price and interest rate swap transactions entered into as hedges are deferred so that the gain or loss is recognized in the period in which the revenues or expenses associated with the hedged transactions are applicable.
In certain situations, the Company has designated portions of and may in the future designate certain commodity price swap transactions or portions thereof as for trading purposes. These transactions are accounted for using the mark-to-market method of accounting. Under this method, unrealized gains or losses resulting from the impact of price movements are recognized as net gains or losses in Net Operating Revenues in the consolidated statements of income.
CAPITALIZED INTEREST COSTS. Certain interest costs have been capitalized as a part of the historical cost of unproved oil and gas properties. Interest costs capitalized during each of the three years in the period ended December 31, 1994 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 even if such benefits could not have been used by the Company or the subsidiary on a separately filed tax return.
The Company has 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.
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 accounts for income taxes under the provisions of Statement of Financial Accounting Standards (SFAS) No. 109 - "Accounting for Income Taxes". SFAS No. 109 requires the asset and liability approach for accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases (See Note 8 "Income Taxes").
FOREIGN CURRENCY TRANSLATION. For subsidiaries whose functional currency is deemed to be other than the U.S. dollar, asset and liability accounts are translated at year-end exchange rates and revenue and expenses are translated at average exchange rates prevailing during the year. Translation adjustments are included as a separate component of shareholders' equity.
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:
1994 1993 1992 ----------- ----------- ----------- Wellhead Natural Gas Revenues Associated Companies(1)(2)....... $ 279,339 $ 340,508 $ 223,249 Trade............................ 162,553 156,301 103,288 ----------- ----------- ----------- Total.................... $ 441,892 $ 496,809 $ 326,537 =========== =========== =========== Other Natural Gas Marketing Activities Gross Revenues from: Associated Companies(3)...... $ 159,726 $ 139,576 $ 186,600 Trade(4)..................... 121,965 135,606 57,482 ----------- ----------- ----------- Total.................... 281,691 275,182 244,082 Associated Costs from: Associated Companies(1)(5)(6)........... 181,756 182,456 133,170 Trade........................ 62,513 66,273 52,283 ----------- ----------- ----------- Total.................... 244,269 248,729 185,453 ----------- ----------- ----------- Net...................... 37,422 26,453 58,629 Commodity Price Hedging Gain (Loss)(7)...................... 10,579 (18,100) 3,822 ----------- ----------- ----------- Total.................... $ 48,001 $ 8,353 $ 62,451 =========== =========== ===========
Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues are comprised of the following: 1994 1993 1992 ----------- ----------- ----------- Wellhead Crude Oil, Condensate and Natural Gas Liquids Revenues Associated Companies............. $ 44,979 $ 38,953 $ 38,474 Trade............................ 29,556 16,881 20,152 ----------- ----------- ----------- Total........................ $ 74,535 $ 55,834 $ 58,626 =========== =========== =========== Other Crude Oil and Condensate Marketing Activities Commodity Price Hedging Gain(7)........................ $ 1,803 $ - $ 301 =========== =========== =========== - --------- (1) Wellhead Natural Gas Revenues in 1994, 1993 and 1992 include $126,783, $129,504 and $84,317, 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 $22,434, $46,358 and $17,173 in 1994, 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 $43,345, $73,867 and $25,380 in 1994, 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 $33,779, $65,042 and $23,977 in 1994, 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 price swap transactions primarily with Enron Corp. affiliated companies based on NYMEX-related commodity prices in effect on dates of execution, less customary transaction fees.
3. OTHER ASSETS
Other Assets at December 31, 1994 includes an investment in 349,387 shares of Enron Corp. common stock purchased for $10 million, at an average of $28.62 per share from Enron Corp. (the fair market value of such shares on the dates of acquisition), in connection with an anticipated acquisition of certain oil and gas properties by a subsidiary of the Company which is scheduled to close in March 1995. The Enron Corp. common stock will be used in connection with the future redemption of redeemable preferred stock to be issued by the subsidiary.
4. LONG-TERM DEBT
REVOLVING CREDIT AGREEMENT. The Company is a party to 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. There were no advances outstanding under the Credit Agreement at December 31, 1994.
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 1994 and 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 would be classified as long-term based on the Company's intent and ability to refinance such amounts using available borrowing capacity.
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. 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 $68.8 million and $60.3 million during 1994 and 1993, respectively. There were no advances outstanding at December 31, 1994 and $96.6 million outstanding at December 31, 1993 under this agreement, which amounts are classified as cash equivalents on the consolidated balance sheets. Interest income recorded in 1994 and 1993 under the terms of this note totaled $4.7 million and $4.4 million, respectively.
In July 1994, the Company prepaid $25 million of loans payable due in April 1995 with proceeds from a promissory note payable to Enron Corp. which note is in the same amount and with essentially the same terms as the loan prepaid. The promissory note is classified as long-term based on the Company's intent and ability to refinance such note upon maturity with other long-term debt. The interest rate swap agreement which effectively fixed the interest rate of the original loan payable at 8.98% through maturity remains in effect for the promissory note payable to Enron Corp.
LONG-TERM DEBT, OTHER. Long-Term Debt, Other at December 31 consisted of the following: 1994 1993 ----------- ----------- Loan(s) Payable.................. $ 25,000 $ 50,000 Senior Notes..................... 70,000 70,000 Promissory Notes................. 56,000 33,000 Commercial Paper................. 6,700 - Capitalized Lease Obligation..... 7,637 - ----------- ----------- Total................ $ 165,337 $ 153,000 =========== ===========
The Loan Payable is due in 1995 and bears interest at a variable rate based on the London Interbank Offered Rate which has, in effect, been converted to a fixed interest rate of 8.92% through maturity using an interest rate swap agreement in equivalent dollar amounts. The note is classified as long-term based on the Company's intent and ability to replace such loan upon maturity with other long-term debt.
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.
In March 1994, a subsidiary of the Company received two advances, evidenced by promissory notes, aggregating $31 million under a credit agreement dated as of March 8, 1994 between the subsidiary and a financial institution. 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 London Interbank Bid Rate which is 1/8 of 1% less than the London Interbank Offered Rate and is due in 1998. Both advances are collateralized 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 a promissory note payable to a bank by the subsidiary.
In May 1994, the subsidiary received a $25 million advance, evidenced by a promissory note, under a credit agreement dated May 27, 1994 between the subsidiary and a financial institution. The credit agreement provides for aggregate borrowings of up to $44 million and is due in 1999. The advances bear interest based on various interest rate options, as defined in the credit agreement, which ranged from 4.03% to 5.59% during 1994. The advance is guaranteed by the Company and was used to partially repay temporary advances from the Company to the subsidiary for qualified development costs.
There was a $6.7 million balance outstanding at December 31, 1994, 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 and are classified as long-term based on the Company's intent and ability to replace such obligation with other long-term debt. The interest rate for the obligation at December 31, 1994 was 6.33%.
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 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, 1994, no debt securities had been issued under this registration statement.
FAIR VALUE OF LONG-TERM DEBT. At December 31, 1994, the Company had $190 million of long-term debt and $2 million of current maturities outstanding. At December 31, 1993, there was $153 million of long-term debt and $30 million of current maturities outstanding. The estimated fair value of such debt, including current maturities, at December 31, 1994 and 1993 was approximately $186 million and $192 million, respectively. The fair value of long-term debt is the value the Company would have to pay to retire the debt, including any premium or discount to the debtholder
for the differential between the stated interest rate and the year-end market rate. The fair value of long-term debt is based upon quoted market prices and, where such quotes were not available, upon interest rates available to the Company at year-end.
5. 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. 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 for equivalent volumes produced and owned by the limited partnership. 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 agreement. Annual remaining amortization of deferred revenue, based on revised scheduled deliveries under the volumetric production payment agreement, as amended, at December 31, 1994 was as follows:
1995................................. $ 43,344 1996................................. 43,463 1997................................. 43,344 1998................................. 43,344 1999................................. 10,688 --------- Total........................ $ 184,183 ========= 6. SHAREHOLDERS' EQUITY
The Board of Directors of the Company approved in December 1992, as amended in September 1994, the purchasing and holding in treasury at any time of up to 500,000 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 Company's stock option plans. (See Note 9 "Commitments and Contingencies - - Stock Option Plans"). At December 31, 1994 and 1993, 9,173 shares and 160,000 shares, respectively, were held in treasury under this authorization.
On May 3, 1994, the shareholders of the Company approved and the Board of Directors subsequently declared a two-for-one split of the Company's common stock to be effected as a non-taxable dividend of one share for each share outstanding. Shares were issued on June 15, 1994 to shareholders of record as of May 31, 1994. An amendment to the Restated Certificate of Incorporation of the Company to increase the total number of authorized shares of the common stock of the Company from 80 million to 160 million shares and to change the par value of common stock from
no par to $.01 par per share was filed with the Secretary of State of Delaware. All share and per share amounts in the financial statements and supplemental financial information have been restated to consider the effect of the two-for-one stock split.
7. TRANSACTIONS WITH ENRON CORP. AND RELATED PARTIES
NATURAL GAS AND CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS NET OPERATING REVENUES. Wellhead Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Revenues and Other Natural Gas and Other Crude Oil and Condensate Marketing Activities include revenues from and associated costs paid to various subsidiaries and affiliates of Enron Corp. pursuant to contracts which, in the opinion of management, are no less favorable than could be obtained from third parties. Other Natural Gas and Other Crude Oil and Condensate Marketing Activities also include certain commodity price swap and NYMEX-related commodity transactions with Enron Corp. affiliated companies which, in the opinion of management, are no less favorable than could be obtained from third parties. (See Note 2 "Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues").
GENERAL AND ADMINISTRATIVE EXPENSES. The Company is charged by Enron Corp. for all direct costs associated with its operations. Such direct charges, excluding benefit plan charges (See Note 9 "Commitments and Contingencies - Employee Benefit Plans"), totaled $13.7 million, $11.5 million and $4.9 million for the years ended December 31, 1994, 1993 and 1992, respectively. Management believes that these charges are reasonable.
Additionally, certain administrative costs not directly charged to any Enron Corp. operations or business segments are allocated to the entities of the consolidated group. Allocation percentages are generally determined utilizing weighted average factors derived from property gross book value, net operating revenues and payroll costs. Effective January 1, 1994, the Company entered into an agreement with Enron Corp. with an initial term of five years through December 1998, which agreement replaced a similar previous agreement, providing for services substantially identical in nature and quality to those services previously provided and for allocated indirect costs incurred in rendering such services up to a maximum of $6.7 million for 1994, such cap to be increased in subsequent years for inflation and certain changes in the Company's allocation bases with any increase not to exceed 7.5% per year. Management believes the indirect allocated charges for the numerous types of support services provided by the corporate staff are reasonable. Approximately $6.6 million, $7.9 million and $9.5 million were charged to the Company for indirect general and administrative expenses for the years ended December 31, 1994, 1993 and 1992, respectively.
FINANCING. See Note 4 "Long-Term Debt - Financing Arrangements with Enron Corp." for a discussion of financing arrangements with Enron Corp.
8. INCOME TAXES
The principal components of the Company's net deferred income tax liability at December 31, 1994 and 1993 were as follows:
1994 1993 ----------- ----------- Deferred Income Tax Assets Non-Producing Leasehold Costs...... $ 7,685 $ 5,234 Seismic Costs Capitalized for Tax.............................. 4,683 5,643 Other.............................. 4,194 6,337 ----------- ----------- Total Deferred Income Tax Assets....................... 16,562 17,214 Deferred Income Tax Liabilities Oil and Gas Exploration and Development Costs Deducted for Tax Over Book Depreciation, Depletion and Amortization....... 252,599 276,422 Capitalized Interest............... 5,763 6,866 Volumetric Production Payment Book Revenue Over Income for Tax...... 26,777 1,288 Other.............................. 715 2,792 ----------- ----------- Total Deferred Income Tax Liabilities.................. 285,854 287,368 ----------- ----------- Net Deferred Income Tax Liability.................... $ 269,292 $ 270,154 =========== ===========
The components of income (loss) before income taxes were as follows:
1994 1993 1992 ----------- ----------- ----------- United States........................ $ 125,510 $ 117,460 $ 74,226 Foreign.............................. 28,425 (5,187) 5,618 ----------- ----------- ----------- Total........................ $ 153,935 $ 112,273 $ 79,844 =========== =========== ===========
Total income tax provision (benefit) was as follows:
1994 1993 1992 ----------- ----------- ----------- Current: Federal.......................... $ 113 $ (52,555) $ (292) State............................ 2,745 5 2 Foreign.......................... 1,291 1,186 471 ----------- ----------- ----------- Total........................ 4,149 (51,364) 181 Deferred: Federal.......................... 3,818 20,845 (21,729) State............................ (14,414) 4,357 3,119 Foreign.......................... 12,384 410 693 ----------- ----------- ----------- Total........................ 1,788 25,612 (17,917) ----------- ----------- ----------- Income Tax Provision (Benefit)..... $ 5,937 $ (25,752) $ (17,736) =========== =========== ===========
The differences between taxes computed at the U.S. federal statutory tax rate and the Company's effective rate were as follows:
1994 1993 1992 ----------- ----------- ----------- Statutory Federal Income Tax Rate.... 35.00% 35.00% 34.00% State Income Tax, Net of Federal Benefit............................ (4.93) 2.53 2.58 Income Tax Related to Foreign Operations......................... 3.44 3.08 (2.07) Tight Gas Sand Federal Income Tax Credits............................ (23.71) (58.05) (54.24) Revision of Prior Years' Tax Estimates.......................... (3.25) (10.73) - Amended Return Recoveries............ (2.62) - (0.84) Federal Tax Rate Increase............ - 5.23 - Other................................ (0.07) - (1.64) ----------- ----------- ----------- Effective Income Tax Rate........ 3.86% (22.94)% (22.21)% =========== =========== ===========
Current income tax receivable from (payable to) Enron Corp. at December 31, 1994, 1993 and 1992 amounted to $(506), $(6,892) and $5,619, 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 $64 million at December 31, 1994 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.
9. COMMITMENTS AND CONTINGENCIES
EMPLOYEE BENEFIT PLANS. Employees of the Company are covered by various retirement, stock purchase and other benefit plans of Enron Corp. During each of the years ended December 31, 1994, 1993 and 1992, the Company was charged $5.1 million, $4.5 million and $3.6 million, respectively, for all such benefits, including pension expense totaling $0.3 million, $0.5 million and $0.5 million, respectively, by Enron Corp.
As of September 30, 1994, 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 $18.9 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 8.0%, 10.5% and 4.0%, respectively.
The Company also has in effect pension and savings plans 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. Benefits are provided under the provisions of a contributory defined dollar benefit plan. The Company accrues the cost of these postretirement benefits over the service lives of the employees expected to be eligible to receive such benefits. The transition obligation existing at January 1, 1993 is being amortized over an average period of 19 years. The accumulated postretirement benefit obligation ("APBO") existing at December 31, 1994 totaled $106.7 million, of which $91.0 million is applicable to current retirees and current employees eligible to retire. The measurement of the APBO assumes an 8% discount rate and a health care cost trend rate of 12.3% in 1994 decreasing to 5% by the year 2006 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 $7.9 million and $0.8 million, respectively. The Company does not currently intend to prefund its obligations under its postretirement welfare benefit plans.
STOCK OPTION PLANS. The Company has various stock option plans ("the Plans") under which employees of the Company and its subsidiaries and non-employee members of the Board of Directors have been or may be granted rights to purchase shares of common stock of the Company generally at a price not less than the market price of the stock at the date of grant. Options granted under the Plans vest over a period of time based on the nature of the grants and as defined in the individual grant agreements.
The following table sets forth the transactions for the Plans for the years ended December 31:
NUMBER OF STOCK OPTIONS ----------------------------------------- 1994 1993 1992 ------------- ------------ ------------ Outstanding at January 1............ 4,124,800 3,908,050 - Granted......................... 5,128,095(1) 920,600 4,048,050 Exercised....................... (1,967,920) (671,850) (127,500) Forfeited....................... (70,420) (32,000) (12,500) ------------- ------------ ------------ Outstanding at December 31 (Grant Prices of $9.25-$23.81 per Share)............................ 7,214,555 4,124,800 3,908,050 ============= ============ ============ Available for Grant at December 31.. 3,218,175 1,075,850 1,964,450 ============= ============ ============ - --------- (1) Includes 1,920,275 options granted on December 30, 1994 under an all employee stock option grant.
At December 31, 1994, 1,826,880 options outstanding were vested. Of the remaining unvested options, 2,802,530, 892,780, 727,030, 581,280 and 384,055 vest in the years 1995, 1996, 1997, 1998 and 1999, respectively.
During 1994, 1993 and 1992, the Company purchased or was tendered 1,817,093, 831,850 and 127,500 of its common shares, respectively, and delivered such shares upon the exercise of stock options, except for shares held in treasury at December 31, 1994 and 1993 as set out below. The difference between the cost of the treasury shares and the exercise price of the options, net of federal income tax benefit of $7.2 million and $2.8 million for the years 1994 and 1993, respectively, is reflected as an adjustment to Additional Paid In Capital. In October 1993, as amended in September 1994, the Company commenced a stock repurchase program authorized by the Board of Directors to facilitate the availability of treasury shares of common stock for, but not limited to, the settlement of employee stock option exercises pursuant to the Plans. At December 31, 1994 and 1993, 9,173 and 160,000 shares, respectively, were held in treasury under this authorization. (See Note 6 "Shareholders' Equity").
LETTERS OF CREDIT. At December 31, 1994 and 1993, the Company had letters of credit outstanding totaling approximately $32.2 and $46.2 million, respectively. The letters of credit outstanding at December 31, 1994 and December 31, 1993 include $31.9 million issued in connection with a loan between one of the Company's subsidiaries and a trust and $33 million issued in connection with a promissory note between the subsidiary and a bank, respectively.
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. On April 6, 1994, Enron Corp. was granted summary judgment wherein the court ordered that TransAmerican can take nothing on its claims against Enron Corp. Trial, which was set most recently for September 12, 1994 has been continued and there is no current setting. 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.
10. CASH FLOW INFORMATION
Gains on sales of certain oil and gas reserves and related assets in the amount of $54.0 million, $13.3 million and $6.0 million for the years ended December 31, 1994, 1993 and 1992, respectively, are required by current accounting guidelines to be removed from Net Income in connection with determining Net Operating Cash Inflows while the related proceeds are required to be classified as investing cash inflows. The Company believes that proceeds from the sales of reserves and related assets should be considered in analyzing the elements of operating cash inflows. The current federal income tax impact of these sales transactions was calculated by the Company to be $19.8 million, $8.2 million and $8.2 million for the years ended December 31, 1994, 1993 and 1992, respectively, which entered into the overall calculation of current federal income tax. The Company believes that this federal income tax impact should also be considered in analyzing the elements of the cash flow statement.
Cash paid for interest and paid (received) for income taxes was as follows for the years ended December 31: 1994 1993 1992 ---------- ---------- ---------- Interest (net of amount capitalized)....................... $ 10,436 $ 10,517 $ 21,576 Income taxes......................... 1,352 (65,543) 7,365
11. BUSINESS SEGMENT INFORMATION
The Company's operations are all natural gas and crude oil exploration and production related. Accordingly, such operations are classified as one business segment. Financial information by geographic area is presented below for the years ended December 31, or at December 31:
12. OTHER INCOME (EXPENSE)
Other income (expense) consisted of the following for the years ended December 31: 1994 1993 1992 ----------- ----------- ----------- Interest Income...................... $ 4,990 $ 5,789 $ 1,555 Reserve Accruals..................... (3,143) (2,520) (2,194) Contract Settlements................. - 4,248 - Other, Net........................... 936 (882) (2,837) ----------- ----------- ----------- Total........................ $ 2,783 $ 6,635 $ (3,476) =========== =========== ===========
13. PRICE AND INTEREST RATE RISK MANAGEMENT
Periodically, the Company enters into certain trading and non-trading activities including NYMEX-related commodity market transactions and other contracts. The non-trading portions of these activities have been designated to hedge the impact of market price fluctuations on anticipated commodity delivery volumes or other contractual commitments. Gains and losses relating to trading transactions were not material to the accompanying consolidated financial statements. All trading positions were closed subsequent to year-end.
INTEREST RATE SWAP AGREEMENTS. In early 1992, the Company entered into interest rate swap agreements to hedge certain floating interest rate exposure in 1992 and 1993. This floating rate exposure arises from debt with interest payments subject to floating interest rates. (See Note 4 "Long-Term Debt"). The notional value of these interest rate swap agreements was $75 million. Effective January 1, 1993, Enron Corp. assumed the Company's remaining obligations under these swap agreements.
At December 31, 1994, the Company had outstanding interest rate swap agreements with notional principal amounts of $50 million which terminate in April 1995. The interest rate swap agreements were entered into to hedge certain floating rate obligations and effectively fix the interest rate on the notional amount of debt at 8.98% and 8.92%. The estimated fair value of the outstanding swap agreements at December 31, 1994 was a negative $0.5 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, 1994, there were no foreign currency contracts outstanding.
ENERGY COMMODITY PRICE SWAPS. The Company entered into certain commodity price swap agreements to, in effect, hedge the market risk caused by fluctuations in the cost of natural gas. The agreements call for the Company to make payments to (or receive payments from) counterparties based upon the differential between a fixed and a variable price for natural gas volumes specified by the contracts. Such natural gas price swap agreements run for periods of up to ten years expiring in 1999. The Company is the fixed price payor on a notional quantity of 66 trillion British thermal units ("TBtu") of natural gas with a fair value of negative $103.7 million at December 31, 1994. The agreements were entered into to, in effect, fix the price of certain purchases which are used to supply a fixed price sales contract. Inclusive of the effect of the price swap, the differential between the escalating fixed purchase price and the escalating fixed sales price results in profit margins ranging from $1.15 per million British thermal unit ("MMBtu") to $1.44 per MMBtu on approximately 66 TBtu to be purchased and delivered for sale over the remaining term of the contracts.
From time to time, the Company enters into primarily NYMEX-related commodity market transactions with affiliates of Enron Corp. to, in effect, mitigate the risk of market price fluctuations on future deliveries of certain portions of its natural gas and crude oil and condensate. At December 31, 1994, the Company had outstanding positions covering notional volumes of approximately 50 TBtu and 51 TBtu of natural gas for the years 1995 and 1996, respectively and approximately 2.5 million barrels ("MMBbl") of crude oil for the year 1995, 1.3 MMBbl of crude oil for the year 1996 and 1.1 MMBbl of crude oil for each of the years 1997 through 1999. The fair value of the positions was $30.7 million at December 31, 1994.
The following table summarizes the estimated fair value of financial instruments and related transactions for non-trading activities at December 31, 1994:
CARRYING ESTIMATED AMOUNT FAIR VALUE(1) -------- ------------- (IN MILLIONS) Long-Term Debt(2).................... $ 190.3 $ 185.7 Interest Rate Swap Agreements(2)..... - (0.5) Foreign Currency Contracts........... - - Energy Commodity Price Swaps(3)...... - (103.7) Related Fixed Price Sales Contract(3)........................ - 170.8 NYMEX-Related Commodity Market Positions.......................... - 30.7 - --------- (1) Estimated fair values have been determined by using available market data and valuation methodologies. Judgment is necessarily required in interpreting market data and the use of different market assumptions or estimation methodologies may affect the estimated fair value amounts.
(2) See Note 4 "Long-Term Debt."
(3) The fair value of the Energy Commodity Price Swaps should be considered with the fair value of the Related Fixed Price Sales Contract in determining the overall market risk of these related business transactions.
CREDIT RISK. While notional contract amounts are used to express the magnitude of price and interest rate swap agreements, the amounts potentially subject to credit risk, in the event of nonperformance by the other parties, are substantially smaller. The Company does not anticipate nonperformance by the other parties.
14. CONCENTRATION OF CREDIT RISK
Substantially all of the Company's accounts receivable at December 31, 1994 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.
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, 1994, 1993 and 1992 were based on studies performed by the Company's engineering staff for reserves in the United States, Canada, Trinidad and India. Opinions by DeGolyer and MacNaughton, independent petroleum consultants, for the years ended December 31, 1994, 1993 and 1992 covering producing areas containing 59%, 65% and 69%, 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, 1994 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, 1994, 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, 1994 and 1993:
1994 1993 -------------- -------------- Proved properties.................... $ 2,889,242 $ 2,675,419 Unproved properties.................. 126,193 96,801 -------------- -------------- Total............................ 3,015,435 2,772,220 Accumulated depreciation, depletion and amortization................... (1,330,624) (1,226,175) -------------- -------------- Net capitalized costs................ $ 1,684,811 $ 1,546,045 ============== ==============
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:
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, 1994.
UNAUDITED QUARTERLY FINANCIAL INFORMATION
SCHEDULE II
ENRON OIL & GAS COMPANY SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992 (IN THOUSANDS)
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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.
3.1(a) - Restated Certificate of Incorporation of Enron Oil & Gas Company (Exhibit 3.1 to Form S-1).
3.1(b) - Certificate of Amendment of Restated Certificate of Incorporation of Enron Oil & Gas Company (Exhibit 4.1(b) to Form S-8 Registration Statement, Registration No. 33-52201, filed on February 8, 1994).
3.1(c) - Certificate of Amendment of Restated Certificate of Incorporation of Enron Oil & Gas Company (Exhibit 4.1(c) to Form S-8 Registration Statement, Registration No. 33-58103, filed on March 15, 1995).
3.2* - Bylaws of Enron Oil & Gas Company.
3.3 - Specimen of Certificate evidencing the Common Stock (Exhibit 3.3 to Form S-1).
4.1 - Promissory Note due May 1, 1996, dated May 1, 1991 (Exhibit 4.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1991).
4.3 - Amended and Restated Enron Oil & Gas Company 1994 Stock Plan (Exhibit 4.3 to Form S-8 Registration Statement, Registration No. 33-58103, filed on March 15, 1995).
10.1 - Services Agreement, dated as of January 1, 1994, between Enron Oil & Gas Company and Enron Corp. (Exhibit 10.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993).
10.2 - Stock Restriction and Registration Agreement dated as of August 23, 1989 (Exhibit 10.2 to Form S-1).
10.3 - Tax Allocation Agreement dated as of August 23, 1989 (Exhibit 10.3 to Form S-1), and First Amended and Restated Tax Allocation Agreement dated as of August 9, 1991, as amended on February 6, 1992 (Exhibit 10.3 to Form S-1 Registration Statement, Registration No. 33-50462, filed on August 5, 1992).
10.4 - Enron Corp. Deferral Plan dated December 10, 1985 (Exhibit 10.12 to Form S-1).
10.5 - Enron Corp. 1988 Stock Plan (Exhibit 10.13 to Form S-1).
10.7 - Enron Corp. 1984 Stock Option Plan (Exhibit 10.15 to Form S-1).
10.8 - Enron Corp. 1986 Stock Option Plan (Exhibit 10.16 to Form S-1).
10.9(a) - Employment Agreement between Enron Oil & Gas Company and Forrest Hoglund, dated as of September 1, 1987, as amended (Exhibit 10.19 to Form S-1), and Second and Third Amendments to Employment Agreement dated June 30, 1989 and February 14, 1992, respectively (Exhibit 10.10 to Form S-1 Registration Statement, Registration No. 33-50462, filed on August 5, 1992).
10.9(b)* - 4th Amendment to Employment Agreement dated December 14, 1994, among Enron Corp., Enron Oil & Gas Company and Forrest Hoglund.
10.10 - Fuel Supply Contract, dated as of June 30, 1986, by and between Enron Oil & Gas Company, HNG Oil Company, BelNorth Petroleum Corporation and Enron Cogenration One Company, as amended (Exhibit 10.23 to Form S-1).
10.11 - Gas Sales Contract dated September 2, 1987 between Enron Oil & Gas Company and Cogenron Inc., as amended (Exhibit 10.24 to Form S-1).
10.12 - Letter Agreement dated August 20, 1987 between Enron Oil & Gas Company and Panhandle Gas Company (Exhibit 10.25 to Form S-1).
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10.13 - Pension Program for Enron Corp. Deferral Plan Participants, effective January 1, 1985, as amended (Exhibit 10.29 to Form S-1).
10.14 - Enron Oil & Gas Company 1993 Nonemployee Director Stock Option Plan (Exhibit 10.14 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992).
10.15(a) - Credit Agreement, dated as of March 11, 1994, among Enron Oil & Gas Company, the Banks named therein and Texas Commerce Bank, National Association, as Administrative Agent and Promissory Note due January 15, 1998, dated March 11, 1994 to the order of Texas Commerce Bank National Association, Promissory Note due January 15, 1998, dated March 11, 1994 to the order of The Bank of New York, Promissory Note due January 15, 1998, dated March 11, 1994 to the order of The Bank of Nova Scotia, Promissory Note due January 15, 1998, dated March 11, 1994 to the order of Credit Lyonnais Cayman Islands Branch, Promissory Note due January 15, 1998, dated March 11, 1994 to the order of Credit Suisse, Promissory Note due January 15, 1998, dated March 11, 1994 to the order of The First National Bank of Chicago, and Promissory Note due January 15, 1998, dated March 11, 1994 to the order of Bank of America National Trust and Savings Association (Exhibit 10.15 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993).
10.15(b)* - Assignment and Acceptance dated April 14, 1994, between Texas Commerce Bank National Association and Royal Bank of Canada and Promissory Note due January 15, 1998, dated April 14, 1994, to the order of Texas Commerce Bank National Association and Promissory Note due January 15, 1998, dated April 14, 1994, to the order of Royal Bank of Canada.
10.16 - Interest Rate and Currency Exchange Agreement, dated as of June 1, 1991, between Enron Risk Management Services Corp. and Enron Oil & Gas Market- ing, Inc. (Exhibit 10.17 to the Company's Annual Report on Form 10-K for the year ended December 31, 1991), Confirmation dated June 14, 1992 (Exhibit 10.17 to Form S-1 Registration Statement, Registration No. 33-50462, filed on August 5, 1992) and Confirmations dated March 25, 1991, April 25, 1991, and September 23, 1992 (assigned to Enron Risk Management Services Corp. by Enron Finance Corp. pursuant to an Assignment and Assumption Agreement, dated as of November 1, 1993, by and between Enron Finance Corp., Enron Risk Management Services Corp. and Enron Oil & Gas Marketing, Inc.). (Exhibit 10.16 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993).
10.17 - Assignment and Assumption Agreement, dated as of November 1, 1993, by and between Enron Oil & Gas Marketing, Inc., Enron Oil & Gas Company and Enron Risk Management Services Corp. (Exhibit 10.17 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993).
10.18 - ISDA Master Agreement, dated as of November 1, 1993, between Enron Oil & Gas Company and Enron Risk Management Services Corp., and Confirmation Nos. 1268.0, 1286.0, 1291.0, 1292.0, 1304.0, 1305.0, 1321.0, 1335.0, 1338.0, 1370.0, 1471.0, 1485.0, 1486.0, 1494.0, 1495.0, 1509.0, 1514.0, 1533.01, 1569.0, 1986.0, 2217.0, 2227.0, 2278.0, 2299.0, 2372.0, 2647.0 (Exhibit 10.18 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993).
10.19 - Letter Agreement between Colorado Interstate Gas Company and Enron Oil & Gas Marketing, Inc. dated November 1, 1990 (Exhibit 10.18 to the Company's Annual Report on Form 10-K for the year ended December 31, 1990).
10.22 - Gas Sales Agreement between Enron Gas Marketing, Inc. and Enron Oil & Gas Marketing, Inc. dated August 22, 1989 (Exhibit 10.38 to Form S-1).
10.23 - Gas Purchase Agreement between Enron Oil & Gas Company and Enron Oil & Gas Marketing, Inc. dated August 22, 1989 (Exhibit 10.41 to Form S-1).
10.24 - Gas Purchase Agreement between Enron Oil & Gas Company and Enron Oil & Gas Marketing, Inc. dated August 22, 1989 (Exhibit 10.42 to Form S-1).
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10.25 - Enron Corp. 1991 Stock Plan (Exhibit 10.08 to Enron Corp. Annual Report on Form 10-K for the year ended December 31, 1991).
10.26 - Enron Corp. 1988 Deferral Plan (Exhibit 10.49 to Form S-1).
10.27 - Form of Enron Corp. Long-Term Incentive Plan Effective as of January 1, 1987 (Exhibit 10.50 to Form S-1).
10.28 - Enron Executive Supplemental Survivor Benefits Plan Effective January 1, 1987 (Exhibit 10.51 to Form S-1).
10.29 - 1988 FlexPerq Program Summary (Exhibit 10.52 to Form S-1).
10.30 - Credit Agreement between Enron Corp. and Enron Oil & Gas Company dated September 29, 1992 (Exhibit 10.28 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992).
10.31 - Credit Agreement between Enron Oil & Gas Company and Enron Corp. dated September 29, 1992 (Exhibit 10.29 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992).
10.33 - Swap Agreement between Banque Paribas and Enron Oil & Gas Company, dated as of December 5, 1990 (Exhibit 10.37 to the Company's Annual Report on Form 10-K for the year ended December 31, 1990), and Confirmations dated March 25, 1991 and April 25, 1991 (Exhibit 10.37 to Form S-1 Registration Statement, Registration No. 33-50462, filed on August 5, 1992).
10.34 - Enron Oil & Gas Company 1992 Stock Plan (Exhibit 10.40 to the Company's Annual Report on Form 10-K for the year ended December 31, 1991).
10.35 - Enron Corp. 1992 Deferral Plan (Exhibit 10.41 to the Company's Annual Report on Form 10-K for the year ended December 31, 1991).
10.36(a) - Conveyance of Production Payment, dated September 25, 1992, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.34 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992).
10.36(b) - First Amendment to Conveyance of Production Payment, dated effective April 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.36(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993).
10.36(c) - Second Amendment to Conveyance of Production Payment, dated effective July 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.36(c) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993).
10.36(d) - Third Amendment to Conveyance of Production Payment, dated effective October 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.36(d) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993).
10.37(a) - Hydrocarbon Exchange Agreement dated September 25, 1992, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.35 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992).
10.37(b)* - Amendment to Hydrocarbon Exchange Agreement dated effective as of January 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership.
10.37(c)* - First Amendment to Hydrocarbon Exchange Agreement dated effective as of April 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership.
10.37(d)* - Second Amendment to Hydrocarbon Exchange Agreement dated effective as of July 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership.
10.37(e)* - Amendment to Hydrocarbon Exchange Agreement dated effective as of August 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership.
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10.37(f) - Fourth Amendment to Hydrocarbon Exchange Agreement, dated effective October 1, 1993, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993).
10.38 - Purchase and Sale Agreement, dated September 25, 1992, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.36 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992).
10.39(a) - Production and Delivery Agreement, dated September 25, 1992, between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.37 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992).
10.39(b) - First Amendment to Production and Delivery Agreement, dated effective April 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.39(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993).
10.39(c) - Second Amendment to Production and Delivery Agreement, dated effective July 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.39(c) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993).
10.39(d) - Third Amendment to Production and Delivery Agreement, dated effective October 1, 1993 between Enron Oil & Gas Company and Cactus Hydrocarbon 1992-A Limited Partnership (Exhibit 10.39(d) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993).
10.40 - Credit Agreement, dated as of March 8, 1994 between Enron Gas & Oil Trinidad Limited and Caribbean Regional Development Investment Trust, and Request for Advance No. 1, dated March 4, 1993, and Request for Advance No. 2, dated March 4, 1993 (Exhibit 10.40 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993).
10.41 - Promissory Note due May 1, 1998, dated as of March 8, 1994, to the order of Caribbean Regional Development Investment Trust (Exhibit 10.41 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993).
10.42 - Promissory Note due May 1, 1998, dated as of March 8, 1994 to the order of Caribbean Regional Development Investment Trust (Exhibit 10.42 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993).
10.43 - Letter of Credit and Reimbursement Agreement, dated March 8, 1994, between Enron Gas & Oil Trinidad Limited and Credit Suisse (Exhibit 10.43 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993).
10.44 - Parent Guaranty, dated March 8, 1994 between Enron Oil & Gas Company and Credit Suisse (Exhibit 10.44 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993).
10.45(a)* - Letter Loan Agreement dated as of May 27, 1994, between Enron Gas & Oil Trinidad Limited and The Bank of Nova Scotia.
10.45(b)* - Promissory Note due May 27, 1999, dated as of May 31, 1994, to the order of The Bank of Nova Scotia.
10.45(c)* - Promissory Note due May 27, 1999, dated as of January 10, 1995, to the order of The Bank of Nova Scotia.
10.46* - Guaranty dated as of May 27, 1994, between Enron Oil & Gas Company and The Bank of Nova Scotia.
10.47* - Attorney Opinion Letter of Enron Oil & Gas International, Inc. dated December 18, 1994 (Panna and Mukta Fields).
10.48* - Certificate of Enron Oil & Gas India Ltd. dated December 22, 1994 (Panna and Mukta Fields).
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10.49* - Financial and Performance Guarantee of Enron Oil & Gas International, Inc. dated December 22, 1994 (Panna and Mukta Fields).
10.50* - Joint Operating Agreement effective as of December 22, 1994, among Oil & Natural Gas Corporation Limited, Enron Oil & Gas India Ltd. and Reliance Industries Limited for contract area identified as Panna and Mukta Fields (Appendices B-1 and B-2 have been intentionally omitted. The Company hereby agrees to furnish a copy of either appendix to the Commission upon request).
10.51* - Production Sharing Contract dated as of December 22, 1994, among The Government of India, Oil & Natural Gas Corporation Limited, Reliance Industries Limited and Enron Oil & Gas India Ltd., for contract area identified as Panna and Mukta Fields [Appendices B-1 and B-2 and Appendix G (Figures G-1, VIIA-1 to 10, VIIB-1 to 20 and VIII-3) have all been intentionally omitted. The Company hereby agrees to furnish a copy of any such appendix and/or figure to the Commission upon request].
10.52* - Attorney Opinion Letter of Enron Oil & Gas International, Inc. dated December 18, 1994 (Tapti Fields).
10.53* - Certificate of Enron Oil & Gas India Ltd. dated December 22, 1994 (Tapti Fields).
10.54* - Financial and Performance Guarantee of Enron Oil & Gas International, Inc. dated December 22, 1994 (Tapti Fields).
10.55* - Joint Operating Agreement effective as of December 22, 1994, among Oil & Natural Gas Corporation Limited, Enron Oil & Gas India Ltd. and Reliance Industries Limited, for contract area identified as Mid-Tapti and South-Tapti Gas Fields [Appendix B (Figure B-1) has been intentionally omitted. The Company hereby agrees to furnish a copy of such appendix to the Commission upon request].
10.56* - Production Sharing Contract dated as of December 22, 1994, among The Government of India, Oil & Natural Gas Corporation Limited, Reliance Industries Limited and Enron Oil & Gas India Ltd., for contract area identified as Mid and South Tapti Field [Appendix B, Appendix G (Figures G-1, VII-1 to 11, VIII-2 to 4 and Appendix 3) have all been intentionally omitted. The Company hereby agrees to furnish a copy of any such appendix, to the Commission upon request].
22* - List of subsidiaries.
23.1* - Consent of DeGolyer and MacNaughton.
23.2* - Opinion of DeGolyer and MacNaughton dated January 13, 1995.
23.3* - Consent of Arthur Andersen LLP.
24* - Powers of Attorney.
27* - Financial Data Schedule.
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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 22ND DAY OF MARCH, 1995.
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 22ND DAY OF MARCH, 1995.
SIGNATURE TITLE - ----------------------- --------------------------------
/s/FORREST E. HOGLUND Chairman of the Board, President (FORREST E. HOGLUND) and 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)