Item 1. Business
General
EEX Corporation ("EEX" or the "Company") and its predecessors have been engaged in the exploration for and the development, production and sale of natural gas and crude oil since 1918. Its activities are currently concentrated in Texas, the Gulf of Mexico and Indonesia. EEX also provides operation and maintenance services, under contract, to two cogeneration plants ("Plant Operations Business").
EEX is exposed to a number of risks and uncertainties, including risks associated with significant estimates, that are described under "Management's Discussion and Analysis of Financial Condition--Risks, Uncertainties and Critical Accounting Policies and Estimates" in Item 7.
History
Until August 1997, the oil and gas exploration and production business of EEX was conducted through subsidiary and affiliate entities of ENSERCH Corporation ("ENSERCH"). From 1985 to 1994, the business was conducted through Enserch Exploration Partners, Ltd. ("EP"), a limited partnership. At yearend 1994, EP and its affiliates were reorganized into a Texas corporation, Enserch Exploration, Inc. ("Old EEI"), of which ENSERCH owned approximately 99%. The publicly-owned interest in Old EEI increased to approximately 17% in September 1995.
EEX was organized in the State of Texas in 1992 as a wholly-owned subsidiary of ENSERCH. It conducted the Plant Operations Business of ENSERCH under the name of Lone Star Energy Plant Operations, Inc. ("LSEPO"). In 1997, pursuant to a merger agreement between Texas Utilities Company and ENSERCH, Old EEI was merged into LSEPO, with LSEPO being the surviving company ("Merger"). In the Merger, LSEPO changed its name to Enserch Exploration, Inc. ("EEI"). ENSERCH then distributed its entire 83% ownership interest in EEI pro rata to ENSERCH's shareholders in a tax-free distribution ("Distribution"). The Merger and the Distribution were each effective on August 5, 1997. On December 19, 1997, EEI changed its name to EEX Corporation.
Strategy
The Company's strategy is to grow its onshore U.S. oil and gas reserves and production, realize value from its undeveloped leases in the Gulf of Mexico and sell or otherwise use its currently inactive Floating Production System ("FPS") and two associated pipelines and other supporting facilities ("Pipelines").
EEX's liquidity is impaired and the independent auditors have issued an audit report with a report modification for a going concern uncertainty. This report modification will result in a default under the current credit facility. If the current revolving credit agreement is not replaced with another borrowing facility, EEX would be required to repay the amount outstanding under the revolving credit agreement on June 27, 2002, or earlier if EEX is in default under the agreement and the lenders accelerate the maturity. EEX is exploring various other options including the raising of additional capital, the sale or merger of the Company or a sale of a significant portion of its assets to repay the loan. In the event these efforts are unsuccessful, EEX may seek protection from its creditors and reorganization under the Federal bankruptcy laws. The following paragraphs describing EEX's strategy assume that EEX is successful in concluding the extension or replacement of existing borrowings or the raising of additional capital. No assurances can be given that EEX will be successful in completing an acceptable financing plan or a sale or merger of the Company.
At the end of 1999, the Company acquired the domestic exploration and production operations of Tesoro Petroleum Corporation. This acquisition supplemented existing production, lengthened average reserve life, provided reinvestment opportunities in faster payback projects and resulted in a stronger foundation from which
to pursue exploration potential in the Gulf of Mexico. The Company's strategy is intended to provide reserve and production growth and improve investment and operating efficiency. The major elements of this strategy are:
Grow the Onshore U.S. Business--During 2000 and 2001, the Company successfully invested a large portion of its capital program in its onshore properties with very favorable results. The Company's 2001 drilling program was successful in 55 out of 65 wells drilled. EEX's estimate of total proved reserve additions and revisions (including minority interest) from the onshore program is approximately 98 billion cubic feet equivalent of natural gas ("Bcfe"), or 213%, of the 46 Bcfe produced during 2001. All reserve additions were achieved through the drilling program. Adjusted for production and asset sales, onshore reserves (including minority interest) increased by approximately 12%. These reserve additions and revisions were achieved at a favorable economic finding and development cost of approximately $1.11 per thousand cubic feet equivalent of natural gas ("Mcfe"). The Company intends to invest a significant portion of its 2002 capital budget in the onshore business through exploration, development, acquisition of producing properties, and/or investments in new leaseholds. The level of investment in 2002, however, is expected to be approximately $40 million, significantly lower than 2001 as a result of lower gas prices and limitations in funds available for investment. This reduction in capital spending could have an adverse impact on production levels during the year and reserves reported at yearend 2002.
Realize Value from the FPS and Pipelines--The Company owns a 60% interest in the FPS and Pipelines. The FPS is a combination Deepwater drilling rig and processing facility capable of simultaneous drilling and production operations. The facility is capable of processing up to approximately 40,000 barrels of oil and 100 million cubic feet of gas daily for transport into a pipeline system. The Pipelines are each approximately 53 miles long and have estimated daily throughput capacity of 70,000 barrels of oil and 140 million cubic feet of gas. A processing facility located at the terminus of the pipelines in shallow water is also 60% owned by EEX. These assets are not currently in service following the abandonment of the Cooper Field. The Pipelines are located approximately six miles from the Llano discovery well and may have utility as support infrastructure for anticipated developments at Llano and the greater Llano complex. The FPS and Pipelines are unique assets constructed for a particular purpose. The possible uses for these assets will affect their ultimate value. The Company is presently evaluating options to realize the value of the FPS following notification from the Llano Field operator in February 2002 that the FPS was no longer being considered for use in a Llano development. The Pipelines remain under consideration as a transportation alternative for the Llano Field. See U.S. Exploration and Development--Offshore--Deepwater Gulf of Mexico Exploration and FPS and Pipelines.
Explore the Deep Potential of EEX's Gulf of Mexico Lease Portfolio--The Company believes that potential reserves under its leasehold interests in the Gulf of Mexico in water depths greater than 600 feet ("Deepwater") may provide the basis for significant long-term production growth. EEX currently holds 68 Deepwater leases, a majority of which are located in water depths between 1,500 and 3,500 feet. To reduce the financial risk associated with dry holes and to accelerate a drilling program, a joint venture was formed with Enterprise Oil PLC ("Enterprise") in 1997. This joint venture provided that Enterprise would fund a portion of EEX's share of exploratory well costs and certain appraisal and development costs in return for one-half of EEX's working interest in 78 Deepwater leases. The exploratory and appraisal well funds due under this agreement were fully paid as of December 31, 2000. Development funds under this agreement are contingent on approval of development plans. EEX has no Deepwater proved reserves in its yearend reserve determination.
In late 1998, the Company began geologic and geophysical studies to identify reserve potential in formations deeper than that conventionally pursued on the Gulf of Mexico in water depths of less than 600 feet ("Deep Shelf"). The Company believes it is economically more attractive to explore this potential than to explore in and around existing mature fields (the "Conventional Shelf"). The Company sold its producing fields and a substantial portion of its undeveloped leasehold in the Conventional Shelf and intends to focus technical resources on defining this deeper exploration potential. The Company may in the future change the composition and size of its leasehold position in the Shelf through participation in lease sales, asset trades or sales, acquisition of producing properties and/or permitting some leases to expire.
EEX plans to realize the value of its Deepwater and Deep Shelf lease portfolio through additional joint venture or farmout arrangements as a non- operator to reduce its financial risk. These arrangements will likely result in a substantial dilution of the Company's ownership interest in any affected leases. At yearend 2001, EEX had no such arrangements approved other than the joint venture agreement for the Devil's Island well currently drilling at Garden Banks Block 344.
EEX and another offshore operator entered into an Agreement that resulted in the parties being successful bidders on six federal offshore lease blocks at OCS Lease Sale No. 182 held March 20, 2002. The parties are presently awaiting awarding of the leases covering these six blocks.
U.S. Exploration and Development--Onshore
Onshore operations are located in four oil and gas producing trends: Gulf Coast of Texas and Louisiana, the Val Verde Basin in southwest Texas, the East Texas Basin and the Texas Panhandle. EEX pursues a strategy of "growth through the drillbit" by extending the proved producing trends both laterally and to deeper horizons through its exploration expertise and drilling program. EEX builds its onshore drilling inventory through leasing, farmouts and targeted producing property acquisitions.
During 2001, EEX, through its subsidiaries, invested approximately $109 million in capital and cash exploration expense to increase production and add reserves in their onshore producing assets. This investment program focused primarily on the Val Verde Basin area, Dinn Ranch, Provident City and the Vaquillas Ranch Fields. For the year 2001, production averaged approximately 126 million cubic feet equivalent of natural gas ("MMcfe") per day.
Approximately 68% (282 Bcfe) of the Company's onshore net proved reserve volume is located in 29 producing fields in the Texas Gulf Coast. Highlights from the year 2001 activity regarding the major Gulf Coast producing assets follow:
Dinn Ranch Field. Dinn Ranch Field is located in Duval County, Texas in the Wilcox trend. In 2001, a significant discovery was made in the deep portion of the field and net proved reserve additions of 33 Bcfe were achieved from activity on two wells which were in the process of completion at yearend. These two wells began producing in late February 2002 at a combined rate of approximately 34 MMcfe gross (9 MMcfe net) per day. Net production for the year for the field averaged approximately 2 MMcfe per day. As of the end of the first quarter of 2002, two additional development wells are in process of completion and are expected to be producing to sales in the third quarter of 2002. Discussions are underway with the Company's co-owner to determine development plans for 2002 beyond the two completing wells. The Company owns working interest in the field ranging from 35% to 50%.
Bob West Field. The Bob West Field was discovered in 1990. It is located in the southern part of the Wilcox trend in Starr and Zapata Counties, Texas. In 2001, 3 wells were completed and placed on production. The field's production for the year averaged approximately 24 MMcfe per day (net). The Company owns non-operated working interests in the field that range from 33% to 70%. In addition, the Company owns a non-operated 70% interest in the field's central gas processing facility, which has a gross capacity of 350 million cubic feet of natural gas ("MMcf") per day and a 50% interest in the Starr-Zapata Pipeline, a 26-mile, 20-inch pipeline through which gas from the field area is transported to market. The Company also owns a non-operated 25% interest in the field's central compression facility.
Vaquillas Ranch Field. Vaquillas Ranch Field (EEX 100% interest) is operated by EEX and located in Webb County, Texas in the southern part of the Wilcox trend. In 2001, the Company continued the redevelopment program begun in the fourth quarter of 1999 by drilling and completing 8 wells. The drilling program resulted in an additional 9 Bcfe of proved reserves. Net production for the year averaged approximately 13 MMcfe per day.
Fashing Field. Fashing Field is located in Atascosa County, Texas and produces from the Edwards formation. In 2000, the Company completed a field study that indicated the potential for additional reserves. As a result of the study, 3 wells were drilled and turned to sales in 2001. Net production for the year averaged approximately 8 MMcfe per day. Discussions are underway with the Company's co-owner to determine additional development plans for 2002. The Company owns working interests in the field that range from 47% to 100%.
Provident City Fields. The Provident City Fields are located in Lavaca County, Texas in the Wilcox trend. In 2001, 4 wells were completed to sales and 4 workovers of existing wells were performed resulting in an addition of 12 Bcfe to proved reserves. By yearend, net production increased approximately 255% from the beginning of the year. Net production for the year averaged approximately 3 MMcfe per day with December 2001 net production averaging 8 MMcfe per day. The Company owns working interest in the field ranging from 16% to 100%.
The Val Verde Basin in Texas contains approximately 20% (82 Bcfe) of the Company's onshore net proved reserve volume. The two major EEX fields in this Basin are Vinegarone East and Langtry.
Vinegarone East Field. The Vinegarone East Field (EEX 75% interest), located in Edwards County, Texas, is operated by EEX and produces from Pennsylvanian-aged sands. During the year, 7 wells were drilled resulting in 6 producing wells. Net production for the year averaged 17 MMcfe per day. Production from the field is carried to sales through an 11-mile, 6-inch pipeline owned (75% interest) and operated by the Company.
Langtry Field. The Langtry Field (EEX 45% interest) is located in Val Verde County, Texas and was the Company's most significant onshore exploration discovery in 2000. During 2001, 13 wells were drilled and completed. The field was turned to sales in May 2001 when a 23-mile, 8-inch pipeline was completed. The pipeline is owned (45% interest) and operated by the Company. Net production for the year averaged approximately 10 MMcfe per day. Two additional development wells will be drilled in the second quarter of 2002.
EEX also owns onshore properties located in East Texas and the Texas Panhandle.
U.S. Exploration and Development--Offshore
Deepwater Gulf of Mexico Exploration--In December 2000, EEX announced that the Garden Banks Block 344 No. 3, an exploratory well on the Jason Prospect, had encountered hydrocarbon-bearing sands. The well was drilled to a total depth of approximately 21,000 feet and encountered hydrocarbon-bearing intervals totaling approximately 100 net feet of pay. Early evaluation of the information gathered by well logs, bottom hole pressure tests, fluid samples and side-wall cores indicated the Jason discovery warrants appraisal. The Company is actively seeking joint venturers to appraise this discovery through a sidetrack from the existing well bore or another well at a drilling location elsewhere on the block. EEX owns a 100% working interest and approximately 80% net revenue interest. The Jason discovery may provide an opportunity to utilize EEX's FPS and Pipeline infrastructure. No assurances can be given that an agreement will be reached with potential joint-venturers regarding appraisal of the Jason discovery or that future development of the Jason Prospect will employ the FPS and/or Pipelines.
In May 2001, EEX relinquished operatorship of the Llano Field in Garden Banks Blocks 385 and 386. EEX remained operator of Garden Banks Blocks 344, 387, 388 and the western half of Block 345, where the Jason discovery and the Travis and Devil's Island prospects are located. The Llano owners also agreed to normalize their interests over the Llano Field (Garden Banks Blocks 385 and 386) with EEX holding a 27.5% interest (previously EEX held a 30% interest on Block 386 and a 25% interest on Block 385). In September 2001, EEX sold its 27.5% interest in the Llano Field for $50 million cash plus an overriding royalty interest of 1/2 of 1% for the first 100 million barrels of oil equivalent total production from the Llano Field and 1% on all production thereafter. The effective date of the sale was June 1, 2001 and the purchaser reimbursed all of EEX's costs associated with the Llano No. 4 well that was drilling at that time. The sale resulted in a pre-tax gain for EEX of approximately $27 million ($17 million after-tax) recorded during the third quarter of 2001.
EEX currently has one Deepwater rig under contract. The Global Marine semi- submersible rig, the Arctic I, was delivered to EEX in July 1999, to begin a three-year contract which has a current operating rate of approximately $140,000 per day. This rig was stacked at the conclusion of the Jason well and, in early February 2001, was assigned to another operator at a rate of $55,000 per day until June 2001. EEX incurred approximately $15 million recorded as exploration expense in stacking and subsidy costs during 2001 for the Arctic I rig. The Llano owners used the rig to drill the Llano No. 4 appraisal well and returned the rig to EEX in November 2001.
The rig was moved to EEX's Devil's Island Prospect at Garden Banks Block 344 in the greater Llano area. EEX entered into a joint venture agreement with Amerada Hess Corporation for the drilling of an exploration well on this prospect, utilizing the Arctic I drilling rig at its full day rate. Under the joint venture agreement, Amerada Hess will operate and earn an 80% interest in Garden Banks Block 344 (E/2) and Garden Banks Block 345 by participating with EEX in drilling the well. EEX will retain a 20% working interest after the well is drilled and pay 30% of the costs of the well up to the AFE (Authorization for Expenditure) amount, 20% thereafter. The well began drilling operations in December 2001 and is expected to reach targeted depth in the second quarter of 2002.
The Arctic I rig contract expires in early July 2002. If drilling operations conclude prior to the end of the contract period, EEX will seek an assignment of the rig to another operator at a subsidized rate or decide to "stack" the rig at a total cost of approximately $150,000 per day for the remainder of the contract term.
FPS and Pipelines--During 2001, EEX continued its efforts to place into service the FPS and the Pipelines, both of which are currently not in use. In November 2001, EEX and the co-owner of the FPS and Pipelines submitted a proposal to the Llano owners for their use in support of a Llano Field development. This proposal was subsequently modified to compete with alternative processing and transportation options for the Llano area. In the fourth quarter, the $152 million carrying value of the FPS and Pipelines was impaired to a fair market valuation of $70 million to reflect these modified proposals and values management believes could be received in an orderly sale of the assets. In February 2002, the Llano Field operator notified EEX that the FPS is no longer being considered for use in a Llano development. The Pipelines remain under consideration as a transportation alternative for the Llano Field.
No assurances can be given that the Pipelines will ultimately be used in a Llano Field development or other potential development in the Llano area, or that management's estimated fair market value of the FPS and Pipelines will be realized in the market.
Gulf of Mexico Deep Shelf--In 2001, EEX further developed its geologic interpretation of deeper exploration potential under the Gulf of Mexico Shelf. The Company began marketing efforts to form a joint venture or farmout arrangement with third parties to reduce the financial risk of exploring these leases. No agreements were finalized in 2001 to fund this program.
EEX and another offshore operator entered into an Agreement that resulted in the parties being successful bidders on six federal offshore lease blocks at OCS Lease Sale No. 182 held March 20, 2002. The parties are presently awaiting awarding of the leases covering these six blocks.
Gulf of Mexico Conventional Shelf--In December 2000, EEX sold its interests in approximately 100 Gulf of Mexico Shelf blocks to W&T Offshore, Inc., substantially all of EEX's Shelf production. As part of this sale, EEX retained the rights to deeper, non-producing horizons in ten of these blocks where the Company believes there is deep exploration potential.
International Exploration and Development
The Company plans to exit its portfolio of international assets in 2002.
Indonesia (Onshore Java) Tuban Block--EEX owns a 50% interest in the production-sharing contract relating to the Tuban Block, which includes the Mudi Field. In December 2001, EEX received an acceptable bid for the purchase of the Tuban Block and in March 2002, signed a purchase and sale agreement with an
Indonesian company. A $16 million impairment on the Indonesian assets was incurred in the fourth quarter of 2001 to reflect the difference between the agreed sales price and book value at closing, currently estimated to occur in the second quarter of 2002. The impairment also includes a discount incorporated in the sales price associated with certain receivables.
Indonesia (Offshore Sumatra) Asahan Block--In 1997, EEX acquired a 60% interest in 4,200 square kilometers in the Asahan Block. In 2001, EEX was carried for a 15% interest in an exploration well that encountered hydrocarbons drilled by the farmout operator. These assets are expected to be sold in the second quarter of 2002 along with the Tuban Block as described above.
New Zealand--The Company will relinquish its remaining concession in New Zealand in the second quarter of 2002.
Plant Operations Business
EEX Power Systems Company ("EEXPS"), a division of EEX, provides operation and maintenance services under contract to two cogeneration plants located in Sweetwater, Texas and Bellingham, Washington. EEXPS operates and maintains the facilities under the terms of operation and maintenance contracts that provide EEXPS periodic fees and reimbursement of certain costs. During 2001, EEX attempted to sell its Plant Operations Business but was unable to conclude a sale. Currently, there are no ongoing efforts to sell the Plant Operations Business.
Sales of Natural Gas and Crude Oil
EEX sells its natural gas under both long- and short-term contracts. EEX markets most of its gas through third-party marketing organizations. EEX sells its crude oil under contracts that are for periods of one year or less. Crude oil prices are based upon field posted prices plus bonuses. EEX makes no sales of natural gas and/or crude oil to any customer where the loss of such customer would have a material adverse effect on EEX.
Sales data are set forth under "Selected Operating Data" included as part of Item 6.
EEX utilizes financial instruments to reduce exposure of its oil and gas production to price volatility. See Item 7A, "Quantitative and Qualitative Disclosures about Market Risk," Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations--Oil and Gas Marketing," and Note 16 to Consolidated Financial Statements in Item 8 for additional information on hedging activities.
Competition
All phases of the oil and gas industry are highly competitive. EEX competes in the acquisition of properties, the search for and development of reserves, the production and sale of oil and gas and the securing of the labor, equipment, and capital required to conduct operations. EEX's competitors include major oil and gas companies, independent oil and gas concerns and individual producers and operators. Many of these competitors have financial and other resources that are substantially greater than those available to EEX. Oil and gas producers also compete with other industries that supply energy and fuel.
Government Regulation
The oil and gas industry is extensively regulated by federal, state and local authorities and by governmental agencies of foreign countries. Legislation affecting the oil and gas industry is under constant review for amendment or expansion. Numerous departments and agencies, federal, state and foreign, have issued rules and
regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for the failure to comply. Because these laws and regulations are frequently amended, reinterpreted or expanded, EEX is unable to predict the future cost or impact of complying with such laws and regulations.
Regulation of Onshore Operations--EEX's production of oil and gas in Texas is regulated by the Texas Railroad Commission, and in Louisiana, by the Louisiana Department of Natural Resources. Similar types of regulations are in effect in Indonesia and other foreign countries. Such regulations include requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilling and the plugging and abandonment of wells. EEX's operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells which may be drilled and unitization or pooling of oil and gas properties. In addition, conservation laws establish maximum rates of production requirements regarding the ratability of production.
Regulation of Offshore Operations--Lessees must obtain the approval of the Minerals Management Service ("MMS"), a federal agency, and various other federal and state agencies for exploration, development and production plans prior to the commencement of offshore operations. Similarly, the MMS has promulgated regulations governing the plugging and abandoning of wells located offshore and the removal of all production facilities. The MMS also issues rules on calculation of royalty payments and valuation of production for royalty purposes.
Environmental Matters--EEX's U.S. oil and gas operations are subject to extensive federal, state and local laws and regulations dealing with environmental protection. These laws include the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as "Superfund," and similar state statutes. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, or criminal penalties.
With respect to offshore leases in U.S. waters, EEX's operations are subject to interruption or termination by governmental authorities on account of environmental contamination and other considerations. The Outer Continental Shelf Lands Act ("OCSLA") provides the federal government with broad discretion in regulating the release or continued use of offshore resources for oil and gas production. If the government were to exercise its authority under OCSLA to restrict the availability of offshore oil and gas leases (for example, due to a serious incident of pollution), such an action could have a material adverse effect on EEX's operations.
The Oil Pollution Act of 1990 ("OPA") and regulations thereunder impose a variety of regulations related to the prevention of oil spills and liability for damages resulting from such spills in the United States waters. The OPA assigns liability to each responsible party for oil removal and cleanup costs, and a variety of public and private damages including natural resource damages. In addition, OPA imposes ongoing requirements on responsible parties, including preparation of spill response plans and proof of financial responsibility to cover at least some costs in a potential spill. EEX maintains insurance against costs of cleanup operations, but is not fully insured against all such risks. The Coastal Zone Management Act authorizes state implementation and development of programs containing management measures for the control of nonpoint source pollution to restore and protect coastal waters.
EEX's U.S. onshore operations are subject to numerous laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations, among other things, may impose absolute liability on the lessee under a lease for the cost of clean-up of pollution resulting from a lessee's operations, subject the lessee to liability for pollution damages, require suspension or cessation of operations in affected areas and impose restrictions on the injection of liquids into subsurface aquifers that may contaminate groundwater. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the remediation and clean-up costs and for damages to natural resources.
The operations of EEX are also subject to the Clean Water Act and the Clean Air Act, as amended, and comparable state statutes. EEX may be required to incur certain capital expenditures over the next five to ten years for pollution control equipment. The Company's operations may generate or transport both hazardous and nonhazardous solid wastes that are subject to the requirements of the Resource Conservation and Recovery Act ("RCRA") and comparable state laws and regulations. In addition, EEX currently owns or leases, and has in the past owned or leased, properties that have been used for oil and gas operations for many years. Although EEX has utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by EEX or on or under other locations where such wastes have been taken for disposal. Many of these properties have been operated by third parties whose operations were not under EEX's control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws, and EEX could be required to remove or remediate previously disposed wastes or property contamination or perform remedial plugging operations to prevent future contamination.
EEX's foreign operations are potentially subject to similar governmental controls and restrictions relating to the environment. Requirements of these foreign governmental bodies may include, among other things, controls over the discharge of materials in the environment, standards for removal and cleanup of spills, and restrictions on the handling and disposal of waste materials.
Regulation of Natural Gas Marketing and Transportation--All price and nonprice controls for all sales of natural gas have been removed by federal statute. EEX may sell its natural gas currently at market prices, subject to applicable contract provisions.
The Federal Energy Regulatory Commission ("FERC") regulates interstate natural gas transportation rates and service conditions, which affect the marketing of natural gas produced by EEX, as well as the revenues received by EEX for sales of such natural gas. Since the latter part of 1985, the FERC has endeavored to make interstate natural gas transportation more accessible to gas buyers and sellers on an open and nondiscriminatory basis. The FERC's efforts have significantly altered the marketing and pricing of natural gas, most notably from Order Nos. 636, 636-A, 636-B, 636-C and 637.
The FERC issued Order No. 639 on April 10, 2000, to promote the open and nondiscriminatory pipeline access mandates of the OCSLA. The Order applies to gas transportation service providers on the Outer Continental Shelf that are not subject to FERC jurisdiction under the Natural Gas Act. Order No. 639 imposes certain reporting requirements and provides a mechanism for complaints of discriminatory and anticompetitive shipping practices.
Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, the FERC, state regulatory bodies and the courts. EEX cannot predict when or if any such proposals might become effective, or their effect, if any, on EEX's operations. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue indefinitely into the future. State regulation of gathering facilities generally includes various transportation, safety, environmental, nondiscriminatory purchase and transport requirements, but does not currently entail rate regulation. Growing competitive pressures in marketing natural gas may cause states to regulate gathering facilities more stringently in the future.
In the aggregate, compliance with federal and state rules and regulations is not expected to have a material adverse effect on EEX's operations.
Employees
At January 1, 2002, EEX had 139 full-time employees, 100 of which were involved principally with oil and gas operations. The remaining employees were involved with the Plant Operations Business.
Offices
The principal offices of EEX are located at 2500 CityWest Blvd., Suite 1400, Houston, Texas 77042, and its telephone number is (713) 243-3100. An onshore office is located at 1020 N.E. Loop 410, Suite 700, San Antonio, Texas 78209, and its telephone number is (210) 829-3500. Plant operation offices are maintained in Sweetwater, Texas and Bellingham, Washington.
Item 2.
Item 2. Properties
In December 2000, EEX sold its interests in substantially all of its Gulf of Mexico Shelf production. As part of this sale, EEX retained the rights to deeper, non-producing horizons in ten of the blocks sold.
In 2001, EEX's operations were located in three regions: (i) the Gulf of Mexico--Deepwater, (ii) Onshore and (iii) International, primarily Indonesia. The following table sets forth estimated net proved reserves of EEX by region, as audited by Netherland, Sewell & Associates, Inc.:
- -------- (1) Million cubic feet. (2) Thousand barrels. (3) Million cubic feet of gas equivalent with one barrel of liquid converted to six Mcf of gas. (4) Included in Onshore above. See Note 14 to Consolidated Financial Statements in Item 8 for additional information on Minority Interest.
See Note 24 to Consolidated Financial Statements in Item 8 for additional information on oil and gas reserves.
During 2001, EEX filed Form EIA-23 with the Department of Energy reflecting reserve estimates for the year 2000. Such reserve estimates were not materially different from the 2000 reserve estimates reported in Note 24 to Consolidated Financial Statements in Item 8.
Developed and undeveloped lease acreage as of December 31, 2001 is set forth below:
- -------- (1) Represents the proportionate interest of EEX in the gross acres under lease. (2) Includes 120,678 gross and 101,008 net acres--Gulf of Mexico Shelf.
(3) Does not include 23,040 gross/6,884 net acres (developed deep) or 25,000 gross/7,563 net acres (developed Shelf) wherein EEX only owns rights below the deepest producing reservoir. (4) EEX owns 25% interest by virtue of the Production Sharing Contract. (5) Included in Onshore above. See Note 14 to Consolidated Financial Statements in Item 8 for additional information on Minority Interest.
EEX purchased approximately 30,928 gross/26,608 net acres in 6 offshore blocks (5 Shelf, 1 Deepwater) at Federal OCS Lease Sale 178, Part 1 held March 28, 2001. Additionally, EEX acquired 10,080 net acres in the fourth quarter of 2001 in deepwater blocks in which it already owned an undivided interest. The total number of blocks in which EEX had an interest at yearend was 97 (not including 3 blocks in which EEX has only an overriding royalty interest), with an average working interest of 48.13%. EEX operates 47 of these blocks.
During 2001, EEX relinquished its interest in 18 Gulf of Mexico blocks and sold its interest in one.
The primary terms during which the undeveloped acreage can be retained by payment of delay rentals, or by drilling operations, without the establishment of oil and gas reserves, expire as follows:
- -------- (1) Includes 9,704 gross and 1,941 net Gulf of Mexico Shelf acres. (2) Includes 107,824 gross and 99,060 net Gulf of Mexico Shelf acres.
The Company may allow drilling rights with regard to a portion of the undeveloped acreage to expire before the expiration of primary terms specified in this schedule by non-payment of delay rentals.
Drilling activity during the three years ended December 31 is set forth below:
Productive wells are either producing wells or wells capable of commercial production, although currently shut-in. The term "gross" refers to the wells in which a working interest is owned, and the term "net" refers to gross wells multiplied by the percentage of EEX's working interest owned therein.
At December 31, 2001, EEX was participating in 9 wells (4.4 net), which were either being drilled, or in some stage of completion.
The number of wells drilled is not a significant measure or indicator of the relative success or value of a drilling program because the significance of the reserves and economic potential may vary widely for each project. It is also important to recognize that reported completions may not necessarily correspond to capital expenditures, since Securities and Exchange Commission guidelines do not allow a well to be reported as completed until it is ready for production. In the case of offshore wells, this may be several years following initial drilling because of the timing of construction of platforms, pipelines and other necessary facilities.
The Company owned interest in productive gas and oil wells at December 31, 2001 as follows:
Additional information relating to the oil and gas activities of EEX is set forth in Note 24 to Consolidated Financial Statements in Item 8 and in "Selected Financial and Operating Data" in Item 6.
EEX leases approximately 49,000 square feet of office space for its office in Houston, Texas, expiring in January 2003. EEX leases approximately 19,000 square feet of office space for its office in San Antonio, Texas, expiring in December 2005.
Item 3.
Item 3. Legal Proceedings
EEX is involved in a number of legal and administrative proceedings incident to the ordinary course of its business. In the opinion of management, based on the advice of counsel and current assessment, any liability to EEX relative to these ordinary course proceedings will not have a material adverse effect on EEX's operations or financial condition.
The operations and financial position of EEX continue to be affected from time to time in varying degrees by domestic and foreign political developments as well as legislation and regulations pertaining to restrictions on oil and gas production, imports and exports, natural gas regulation, tax increases, environmental regulations and cancellation of contract rights. Both the likelihood and overall effect of such occurrences on EEX vary greatly and are not predictable.
EEX has taken and will continue to take into account uncertainties and potential exposures in legal and administrative proceedings in periodically establishing accounting reserves.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
None.
PART II
Item 5.
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
The Company's common stock is traded principally on the New York Stock Exchange under the ticker symbol "EEX." The following table shows the high and low sales prices per share of the common stock as reported in the New York Stock Exchange--Composite Transactions report for the periods shown.
At March 31, 2002, EEX had 42,487,395 outstanding shares of common stock held by 9,942 shareholders of record.
There were no dividends declared on the Company's common stock in 2001 or 2000. The declaration of future dividends will be dependent upon business conditions, earnings, cash requirements and other relevant factors as determined by the Company's Board of Directors. Under the terms of the Company's Series B 8% Cumulative Perpetual Preferred Stock (the "Series B Preferred Stock"), the Company may not declare or pay any dividend or make any other distribution on its common stock, unless all dividends due upon the Series B Preferred Stock have been paid or provided for.
Item 6.
Item 6. Selected Financial and Operating Data
EEX CORPORATION
SELECTED FINANCIAL DATA
- -------- (a) The per share amounts for periods prior to 1998 have been restated to reflect the reduction in weighted average shares outstanding due to the one-for-three reverse stock split effective on December 8, 1998.
EEX CORPORATION
SELECTED OPERATING DATA
- -------- (a) Billion cubic feet or billion cubic feet equivalent, as applicable. Ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids. (b) Before related production, severance and ad valorem taxes. (c) One thousand cubic feet or one thousand cubic feet equivalent, as applicable. Ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids. Average sales prices reflect results net of hedged transactions. (d) The year 2001 excludes approximately $15 million of costs associated with stacking of the Arctic I rig and recognition of the net costs associated with the assignment of the Arctic I contract through May 2001. The year 1999 excludes approximately $44 million of dry hole costs associated with the George and Mackerel prospects. (e) One million barrels of crude oil or other liquid hydrocarbons.
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion should be read in conjunction with EEX Corporation's ("EEX" or the "Company") Consolidated Financial Statements and notes thereto included under Item 8.
Certain statements in this report, including statements of EEX and management's expectations, intentions, plans and beliefs, are "forward-looking statements," within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and are subject to certain events, risks and uncertainties that may be outside EEX's control. Actual results and developments could differ materially from those expressed in or implied by such statements due to a number of factors, including, without limitation, those described in the context of such forward-looking statements, the risks, uncertainties and critical accounting policies and estimates set forth below and described from time to time in EEX's other documents and reports filed with the Securities and Exchange Commission ("SEC").
Risks, Uncertainties and Critical Accounting Policies and Estimates
Liquidity--Management is continuing to negotiate for a new credit agreement to replace its current revolving credit agreement that matures on June 27, 2002. EEX has a waiver until April 30, 2002 for exceeding the debt to capital ratio under this agreement. The independent auditors have issued an audit report with a report modification for a going concern uncertainty. This report modification will result in a default under the current credit facility. If the current revolving credit agreement is not replaced with another borrowing facility, EEX would be required to repay the amount outstanding under the revolving credit agreement on June 27, 2002, or earlier if EEX is in default under the agreement and the lenders accelerate the maturity. EEX is exploring various other options including the raising of additional capital, the sale or merger of the Company or a sale of a significant portion of its assets to repay the loan. In the event these efforts are unsuccessful, EEX may seek protection from its creditors and reorganization under the Federal bankruptcy laws. Also, the New York Stock Exchange ("Exchange") may delist EEX's common stock, which could result in decreased liquidity for the common shareholders. EEX currently exceeds the minimum quantitative criteria of the Exchange for continued listing, however, no assurances can be given that the Company will continue to meet these criteria or that the Exchange will not use other criteria or information in considering whether to institute delisting proceedings. A liquidation of assets to retire debt and preferred securities may result in little to no funds remaining for the common shareholders. No assurances can be given that EEX will be successful in completing an acceptable financing plan or a sale or merger of the Company.
A new credit agreement would include financial maintenance covenants. Management believes that EEX would be able to maintain such covenants. However, in the event that EEX's business plan is adversely impacted by the risks, uncertainties and significant estimates described below, EEX could default under its new credit agreement, which would allow the lenders to enforce their security interest in EEX's oil and gas and other assets.
EEX's access to trade credit may become limited because of EEX's financial condition. This would adversely affect working capital. In addition, EEX may not be able to obtain credit to hedge future gas production or may be required to maintain margins for hedges.
Natural Gas Prices--EEX's revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on current market expectations of future prices for natural gas in the United States. Lower prices in the future would have a serious adverse impact on the Company's future financial results, the Company's ability to meet debt covenants expected as part of the Company's refinancing plan, and the Company's ability to access equity and debt markets on favorable terms. Management has taken steps to mitigate a portion of this risk through the use of financial instruments to hedge the price of natural gas during the year 2002 and 2003. Conversely, a rise in natural gas prices above hedge levels during this period would result in the Company not realizing the benefit of this increase on the hedged volumes. These hedges represent only a small portion of EEX's total proved reserves, its principal asset. Lower gas prices would seriously reduce the value of EEX's proved reserves and could impact the Company's annual assessment of
impairment required under Statement of Financial Accounting Standards No. 144 ("SFAS No. 144"), "Accounting for the Impairment or Disposal of Long-Lived Assets" effective January 1, 2002. Although management believes that long-term natural gas prices will be in excess of five-year historical average gas prices of approximately $3.00 per MMBtu (Henry Hub), there can be no assurances that high natural gas prices will, in fact, prevail.
Estimated Value of the FPS and Pipelines--Management assessed the fair value of the FPS and Pipelines to be $70 million at yearend. This value was based upon proposals made by EEX to the Llano Field operator, competition from processing and transportation alternatives, and general estimates of the market for these assets in a third party sale. The FPS and Pipelines are unique assets. The possible uses for these assets will affect their ultimate value. There is no established third party market for these assets; it is very difficult to accurately estimate what a sale would bring. In addition, the carrying value of the assets assumes an orderly disposition of the assets, which may take a significant amount of time. An immediate sale or a sale under distressed circumstances might realize much less than the carrying value of the assets. The value of the Pipelines depends on their use to transport production from the greater Llano or other areas in proximity to the Pipelines. If all producers choose other transportation alternatives, the value of the Pipelines would be seriously reduced. You should not assume that management's estimate of current fair value is a definitive view of the market for these assets. The asset value could be higher or lower than this estimate depending on actual third party markets for the FPS and ultimate utility of the Pipelines. These factors are generally beyond the control of EEX.
Oil and Gas Reserve Estimates--The process of estimating quantities of proved reserves is inherently uncertain, and the reserve data included in this document are only estimates prepared by the Company. Reserve engineering is a subjective process of estimating underground accumulations of hydrocarbons that cannot be measured in an exact manner. The process relies on interpretation of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this data can vary. The process also requires certain economic assumptions regarding drilling and operating expense, capital expenditures, taxes and availability of funds. The SEC mandates some of these assumptions, such as oil and gas prices and the present value discount rate.
Proved reserve estimates prepared by others may be substantially higher or lower than the Company's estimates. Because these estimates depend on many assumptions, all of which may differ from actual results, reserve quantities actually recovered may be significantly different than estimated. Material revisions to reserve estimates may be made depending on the results of drilling, testing, and rates of production.
You should not assume that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance with SEC requirements, the Company based the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate.
The Company's rate of recording depreciation, depletion and amortization expense for proved properties is dependent on the Company's estimate of proved reserves. If these reserve estimates decline, the rate at which the Company records these expenses will increase.
Lower prices could make it uneconomic to drill and produce proved undeveloped reserves.
Estimated Value of EEX's Leasehold and Investment in the Llano Area-- Management believes that this area contains substantial quantities of oil and natural gas, none of which is currently classified as proved reserves. EEX's investment in this area includes a royalty interest in the Llano Field with a carrying value of $12 million, the Jason discovery well with a carrying value of $24 million and the cost of the currently drilling Devil's Island exploration well expected to be approximately $15 million net to EEX. In addition, the Pipelines previously discussed derive their principal value from their utility as transportation for potential yet to be proved reserves in this area. Development of the Llano Field and a possible Devil's Island discovery are outside the control of EEX. Development of the Jason Field depends, in part, on the initial success of other development in the area, of which there are none currently active or approved by their owners. Some factors that may limit future development are
lower commodity prices, low estimates of future recoverable reserves, unfavorable investment economics, availability of capital, and approval by co- owners. To the extent these developments do not ultimately occur, EEX may be required to impair the value of its assets in this area.
Asset Sales--EEX has assumed that it will close the sale of its Indonesian assets during the second quarter of 2002 pursuant to the stock purchase agreements signed as of March 11, 2002. If this sale does not close, EEX's debt would be higher than planned, which may adversely affect EEX's ability to obtain a new credit facility on satisfactory terms.
Successful Efforts Accounting--The successful efforts method of accounting is used for oil and gas operations. Under this method, acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including seismic purchases and processing, exploratory dry hole drilling costs and cost of carrying and retaining unproved properties are expensed as incurred. EEX incurred significant dry hole expense in the past as part of its Gulf of Mexico exploration program. Management believes it can limit Gulf of Mexico offshore exploration risk in the future through farmout of its leasehold interests. In addition, EEX's onshore program is also exposed to risk for drilling exploratory dry holes. EEX is also exposed to potential impairments if the book value of a field or field area exceeds its expected future net cash flows. This may occur if discoveries are less than anticipated, reserves are revised downward, commodity prices fall or costs increase. This determination is made either through recognition of an adverse change or as part of the annual review of all fields. The impairment of unamortized capital costs for a field or field area is reduced to an estimated fair value if it is determined that the sum of expected future net cash flows is less than the net carrying value.
Leasehold costs of producing properties are depleted using the unit of production method based on estimated proved oil and gas reserves quantified on the basis of their equivalent energy content. Amortization of drilling and equipment costs is based on the unit of production method using estimated proved developed oil and gas reserves quantified on the basis of their equivalent energy content. The current undiscounted cost of estimated future site restoration, dismantlement and abandonment, net of salvage, is included in the cost of productive oil and gas properties and a corresponding liability is recorded. The recorded cost is amortized on the unit of production method. Actual costs incurred for these activities are charged to the recorded liability. The sale of the Gulf of Mexico Shelf properties in December 2000 eliminated substantially all of EEX's accrued abandonment liabilities.
Depreciation of other property, plant and equipment is provided principally by the straight line method over the estimated service lives of the related assets as follows: FPS and Pipelines-20 years, leasehold improvements- remaining term of the lease, computer hardware and software- 3 to 5 years, and furniture, fixtures and other-3 to 7 years. Major improvements are capitalized, maintenance and repairs are charged to expense as incurred.
Derivative Instruments--Effective January 1, 2001, EEX adopted Statement of Financial Accounting Standards No. 133 ("SFAS No. 133"), "Accounting for Derivative Instruments and Hedging Activities," as amended, which requires that all derivative instruments be reported on the balance sheet at fair value and that changes in a derivative's fair value be recognized currently in earnings unless specific hedge criteria are met. Fair value is determined based on current market contracts with the same terms and conditions. For derivatives designated as cash flow hedges, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income (loss) and are recognized in the Consolidated Statement of Operations when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges are recognized as a charge or credit to earnings. The Company uses derivative instruments to manage exposures to commodity price risks. Hedging transactions are subject to the Company's risk management policy, which does not permit speculative positions. The Company documents relationships between hedging instruments and hedged items, and assesses and documents, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair values or cash flows associated with the hedged items. None of EEX's current hedges contain requirements to maintain margins. The Company may from time to time settle early derivative transactions. Gains or losses are included in other comprehensive income until they are recognized in revenues to match the underlying sales transaction being hedged. See Item 7A, "Quantitative and Qualitative Disclosures about Market Risk."
Revenue Recognition and Gas Imbalances--The Company follows the sales method of accounting for revenue recognition and gas imbalances, which recognizes over and under lifts of gas when sold, to the extent sufficient gas reserves or balancing agreements are in place. Gas sales volumes are not significantly different from the Company's share of production.
Income Taxes--Under Statement of Financial Accounting Standards No. 109 ("SFAS No. 109"), "Accounting for Income Taxes," deferred income taxes are recognized at each yearend for the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts based on tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. Valuation allowances are established when necessary to reduce the deferred tax asset to the amount expected to be realized. The Company's deferred tax asset is fully reserved as of December 31, 2001.
Arctic I Rig Commitment--The majority of the remaining commitment associated with the Arctic I rig (See Note 19 to Consolidated Financial Statements in Item 8 and the discussion under "U.S. Exploration and Development--Offshore, Deepwater Gulf of Mexico Exploration" in Item 1) will be used for the Devil's Island well which is currently being drilled, and in which EEX pays 30% of the costs of the well up to the AFE amount, 20% thereafter. If the Arctic I is returned to EEX after the drilling of this well and before the end of the contract period, EEX intends to pursue subsidized contract assignments or stack the rig. If EEX cannot find other parties willing to use the rig for the remainder of the contract term, EEX will incur approximately $150,000 per day in expense to stack the rig.
Impairment of Assets--EEX accounts for oil and gas properties using the successful efforts method of accounting, which requires EEX to comply with the requirements of SFAS No. 121. The process by which the Company assesses its oil and gas properties under SFAS No. 121 starts with a comparison of the carrying value of an asset to its estimated future undiscounted net cash flow ("Future Value"). These net cash flows are prepared by the Company. The reserves are audited by its independent petroleum consultant, Netherland, Sewell & Associates, Inc. This analysis uses a multi-year market-based commodity price forecast in effect at yearend 2001. The initial prices used in this analysis for 2002 annual cash flows were $21.00 per barrel of oil and $2.742 per million British Thermal Units of gas ("MMBtu"). This analysis is generally prepared at a field level or field-group level. The fields or groups reflect the lowest level for which cash flows are reasonably and separately identifiable and for which the assets possess common operational infrastructure and geographic proximity. Where insufficient Future Value is projected to recover the carrying value of an asset, a determination of fair value is made. Fair value is estimated for most oil and gas properties by discounting the annual net cash flows at a rate of 10% per annum. The carrying value of the asset is reduced to its estimated fair value.
Exploration Risk--Exploration for oil and gas in the Deepwater Gulf of Mexico and unexplored frontier areas has inherent and historically high risk of economic failure. Onshore U.S. exploration also has inherent risk of economic failure. EEX is focusing on exploration opportunities in onshore and Gulf of Mexico. Future reserve increases and production will be dependent on EEX's success in these exploration efforts and no assurances can be given of such success. Exploration may involve unprofitable efforts, not only with respect to dry wells, but also with respect to wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs.
Operational Risks and Hazards--EEX's operations are subject to the risks and uncertainties associated with finding, acquiring and developing oil and gas properties, and producing, transporting and selling oil and gas. Operations may be materially curtailed, delayed or canceled as a result of numerous factors, such as accidents, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment. Operating hazards such as fires, explosions, blow-outs, equipment failures, abnormally pressured formations and environmental accidents may have a material adverse effect on EEX's operations or financial condition. EEX's ability to sell its oil and gas production is dependent on the availability and capacity of gathering systems, pipelines and other forms of transportation.
Offshore Risks--EEX's Gulf of Mexico oil and gas exploration prospects include properties located in water depths greater than 2,000 feet where operations are by their nature more difficult than drilling operations conducted on land in established producing areas. Deepwater drilling and operations require the application of more advanced technologies that involve a higher risk of mechanical failure and can result in significantly higher drilling and operating costs which, in turn, can require greater capital investment than anticipated and materially change the expected future value of offshore development projects. The size of oil and gas reserves determined through exploration and confirmation drilling operations must ultimately be significant enough to justify the additional capital required to construct and install production and transportation systems and drill development wells. Development of any discoveries made pursuant to EEX's Deepwater exploration program may not return any profit to it and could result in an economic loss. Furthermore, offshore operations require a significant amount of time between the discovery and the time the gas or oil is actually marketed, increasing the market risk involved with such operations.
Government Regulation--EEX's business is subject to certain federal, state and local laws and regulations relating to the drilling for and the production of oil and gas, as well as environmental and safety matters. Enforcement of or changes to these regulations, which EEX is unable to predict, could have a material impact on EEX's operations, financial condition and results of operations.
Results of Operations
EEX reported a 2001 net loss of $160 million ($3.85 per share), a net loss of $10 million ($0.25 per share) in 2000 and a net loss of $100 million ($2.37 per share) in 1999.
In 2001, results of operations were impacted by several major items:
. $127 million pre-tax charge for impairments required by Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," ("SFAS No. 121") incurred during the fourth quarter of 2001. The FPS and Pipelines were impaired $82 million to a fair market valuation based on competitive factors for processing and transportation facilities in the Llano area and the values management believes could be received in an orderly sale of assets. The onshore U.S properties were impaired $29 million, of which $23 million was attributable to the production payment related to the Encogen obligation. The Indonesian assets were impaired $16 million to reflect the agreed price of the potential purchaser of these assets. See Note 9 to Consolidated Financial Statements in Item 8.
. $11 million reduction in the net realizable value of the deferred tax asset in accordance with Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes, " ("SFAS No. 109"). The deferred tax asset of approximately $168 million is fully impaired.
. $4 million extraordinary post-tax gain from the repurchase of a portion of the notes related to the FPS and Pipelines. See Note 7 to Consolidated Financial Statements in Item 8.
. $17 million post-tax gain from the sale of the Llano Field in September 2001 offset by an $18 million pre-tax loss from the exercise by a third party of an option to repurchase a portion of the production payment related to Encogen obligation. In addition, a $4 million pre-tax gain from the sale of the Sheridan Field in September 2001.
In 2000, results of operations were impacted by two major items:
. $12 million pre-tax charge for impairment of producing oil and gas properties required by SFAS No. 121.
. $7 million pre-tax loss on sales of property, plant and equipment.
In 1999, results of operations were impacted by three major items:
. $26 million pre-tax charge for impairment of producing oil and gas properties required by SFAS No. 121.
. $15 million pre-tax gain on sales of property, plant and equipment.
. $44 million pre-tax deepwater dry hole costs associated with the George and Mackerel prospects.
In the following comparisons of results of operations, 2001, 2000 and 1999 results have been adjusted to exclude the items described above.
2001 Results of Operations Compared With 2000
Revenues for 2001 were $207 million, 21% lower than the $262 million reported for the year 2000. Natural gas revenues for the year 2001 were 20% lower than 2000. This decrease was due to a 22% decrease in production, offset slightly by a 3% increase in average natural gas sales prices. The average natural gas sales price per thousand cubic feet (Mcf) was $3.22 for the year 2001, compared with $3.14 in the year 2000. The average natural gas sales price for the year 2001 includes hedging losses of $0.2 million and 21,707 billion British Thermal Units ("BBtu") delivered under fixed-price physical delivery contracts and the Gas Sales Obligation at an average price of $2.601 per MMBtu. The average natural gas sales price of $3.14 per Mcf for the year 2000 includes hedging losses of $20 million and 12,811 BBtu delivered under the Gas Sales Obligation at an average price of $2.519 per MMBtu. Natural gas production for the year 2001 was 43 billion cubic feet (Bcf), compared with 55 Bcf for the year 2000. The decrease in production is primarily due to the sale of the offshore shelf properties. Oil revenues decreased 24% due to an 18% decline in average prices and a 7% decline in production primarily due to the sale of the offshore shelf properties. The average oil price during the year 2001 decreased to $23.47 from $28.54.
Costs and expenses, excluding the unusual items described above, were $193 million, compared with $204 million for the year 2000. Operating expenses (production and operating, general, administrative and other, and taxes other than income) were $70 million in the year 2001, unchanged from 2000. Production and operating and general, administrative and other costs were lower, offset by increased taxes, other than income. Production and operating costs decreased primarily as a result of the sale of the offshore shelf properties, offset by an increase in workover expense. Excluding a bad debt expense of approximately $3 million related to the bankruptcy of Enron Corp., general, administrative and other were down approximately 18% for the year. Exploration expense for the year 2001 increased to $49 million, compared to $34 million for the same period of 2000. Exploration expense includes approximately $15 million in costs associated with the stacking of the Arctic I rig and recognition of the net costs associated with the assignment of the Arctic I contract through May 2001. Also included in exploration expense for 2001 was a $4 million write-off of an offshore lease due to a contract forfeiture. Depletion, depreciation and amortization for the year 2001 was $68 million, $26 million lower than the same period of 2000, primarily due to the sale of the offshore shelf properties and a lower rate on the Mudi Field.
Total interest and other financing costs for the year 2001, including interest income, preferred stock dividends and other income, were $43 million, a $3 million decrease from the same period of 2000, primarily due to lower interest expense related to the debt associated with the FPS and Pipelines and the Gas Sales Obligation, offset by higher interest expense associated with increased borrowings under the revolving credit agreement.
2000 Results of Operations Compared With 1999
Revenues for 2000 were $262 million, $85 million (48%) higher than 1999. Natural gas revenues, 85% higher than 1999, were impacted by a 34% increase in production primarily due to the acquisition of the Tesoro onshore properties in December 1999 and an increase in the unhedged average price of 53%, offset by production decline on properties located in the Gulf of Mexico Shelf. The average unhedged natural gas sales price per Mcf was $3.51 in 2000, compared with $2.29 in 1999. The unhedged gas price includes the effects of the Gas Sales Obligation representing approximately 13 Bcf of gas delivered in 2000 at an average realized price of $2.51 per Mcf. The average natural gas sales price per Mcf (after hedging losses of $20.2 million) was $3.14 in 2000,
compared to $2.28 in 1999, an increase of 38%. Natural gas production for 2000 was 55 Bcf, compared with 41 Bcf in 1999. Oil revenues increased 4% due to higher average oil prices, offset by lower production. A 70% increase in the unhedged average oil price was offset by a $0.1 million oil hedging loss for the year 2000, compared to a $1.3 million oil hedging loss for the year 1999. Crude oil production decreased 40% to 2,726 thousand barrels ("MBbls") in 2000 from 4,528 MBbls in 1999.
Costs and expenses, excluding the unusual items described above, were $204 million in 2000, compared to $192 million in 1999, a 7% increase. Operating expenses (production and operating, general and administrative and taxes other than income) were $70 million in 2000, 4% lower than 1999, resulting from property sales and the favorable impact from restructuring measures implemented over the last year, specifically lower general and administrative cost, offset by higher taxes, other than income, associated with increased gas production from the onshore operations. Exploration expense for 2000 include $4 million for dry hole costs, compared to $51 million in 1999. Depletion, depreciation and amortization was $94 million in 2000, $25 million higher than 1999 due to higher production volumes resulting from the Tesoro onshore property acquisition and increased rates at the Mudi Field, offset by asset sales and production decline primarily on properties located in the Gulf of Mexico Shelf.
Total interest and other financing costs, including interest income, preferred stock dividends, minority interest and other income, were $47 million, a $24 million increase from 1999, resulting primarily from an increase in interest expense due to amounts outstanding under the revolving credit agreement and the Gas Sales Obligation, and by a decrease in interest income due to lower cash balances during 2000.
Oil and Gas Marketing
Results of operations are largely dependent upon the difference between the prices received for oil and gas produced and the costs of finding and producing such resources. On an energy-equivalent basis, U.S. gas reserves at January 1, 2002 constituted approximately 95% of total U.S. reserves (82% of total Company reserves), and U.S. gas production accounted for approximately 94% of total U.S. production (73% of total Company production) for 2001. Accordingly, variations in gas prices have a more significant impact on operations than variations in oil prices.
A portion of the risk associated with fluctuations in the price of oil and natural gas is managed through the use of hedging techniques such as oil and gas swaps and collars. EEX fixed the price on 2001 gas production volumes of approximately 14 Bcf of natural gas (32% of natural gas production), including approximately 5 Bcf of natural gas swaps and 9 Bcf of natural gas collars, but excluding the Gas Sales Obligation and fixed-price delivery contracts. None of EEX's current hedges contain requirements to maintain margins. The average swap price was $3.95 per MMBtu and the average collar strike prices were $2.97 and $4.41 per MMBtu. In total, oil and gas price hedging activities decreased 2001 revenues by $0.2 million, 2000 revenues by $20.3 million and 1999 revenues by $1.9 million. See Item 7A
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133 ("SFAS No. 133"), "Accounting for Derivative Instruments and Hedging Activities", as amended. The effect of adopting this standard was a decrease to shareholders' equity of approximately $20 million, all of which would have been reclassified into earnings during the next twelve months. Due to significant price declines during the year 2001, the net loss related to oil and gas financial hedging activities that was reclassified to revenues to match the underlying sales transaction being hedged was only $0.2 million for the year ended December 31, 2001.
The Company may from time to time settle early derivative transactions. Gains or losses are included in other comprehensive income until they are recognized in revenues to match the underlying sales transaction being hedged. During the fourth quarter of 2001, the Company settled early a derivative transaction for the year 2002 for approximately $6 million and a derivative transaction for the year 2003 for approximately $2 million which will be recognized in earnings in the respective periods.
The Company is exposed to commodity price risk in the normal course of business. Significant changes in commodity prices will have a corresponding change in reported revenues. A portion of the risk associated with fluctuations in the price of natural gas is managed through the use of hedging techniques such as gas swaps and collars. The tables below provide information about EEX's hedging instruments as of December 31, 2001. Since essentially all of the hedging done by EEX utilized either "swap" or "collar" instruments, the tables have been separated to show the volumes hedged utilizing each instrument. The Notional Amount is equal to the volumetric hedge position of EEX during the periods. The fair values of the hedging instruments, which have been recorded in other comprehensive income, are based on the difference between the applicable strike price and the New York Mercantile Exchange future prices for the applicable trading months.
The Company enters into the majority of its hedging transactions with one counterparty and a netting agreement is in place with that counterparty. The Company does not obtain collateral to support the agreements but monitors the financial viability of counterparties and believes its credit risk is minimal on these transactions.
- -------- (1) Billions of British Thermal Units. (2) Millions of British Thermal Units.
Interest Rate Risk--The Company has no open interest rate swap or interest rate lock agreements. At December 31, 2001, the Company's only outstanding debt consisted of secured notes with fixed interest rates. The following table presents principal amounts and related average interest rates by year of maturity for the Company's secured notes at December 31, 2001:
The Company's exposure to interest rate risk is primarily related to future use of its revolving credit facility and to market conditions, as they may exist, should new financings be undertaken. These exposures may be managed through the use of swap or other derivatives as appropriate.
Certain other market risks are disclosed in Item 7 - -Management's Discussion and Analysis of Financial Condition and Results of Operations.
Item. 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT AUDITORS
The Board of Directors and Shareholders of EEX Corporation
We have audited the accompanying consolidated balance sheets of EEX Corporation and subsidiaries (the "Company"), as of December 31, 2001 and 2000, and the related consolidated statements of operations, shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. 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 consolidated financial position of EEX Corporation and subsidiaries at December 31, 2001 and 2000, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.
The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As more fully described in Note 2, the Company has incurred recurring net losses and has a substantial working capital deficiency as of December 31, 2001. In addition, the Company has not complied with certain covenants of loan agreements with banks. These conditions raise substantial doubt about the Company's ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 2. The financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classification of liabilities that may result from the outcome of this uncertainty.
Ernst & Young LLP
Houston, Texas February 20, 2002, except for Note 25 as to which the date is March 11, 2002
EEX CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
See Notes to Consolidated Financial Statements.
EEX CORPORATION
CONSOLIDATED BALANCE SHEET
See Notes to Consolidated Financial Statements.
EEX CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
See Notes to Consolidated Financial Statements.
EEX CORPORATION
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
See Notes to Consolidated Financial Statements.
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
EEX Corporation ("EEX" or the "Company") is an energy exploration company involved in both domestic and international (primarily Indonesia) oil and gas exploration and production. EEX also provides operation and maintenance services, under contract, to two cogeneration plants. Prior to August 5, 1997, Enserch Exploration, Inc. ("Old EEI"), EEX's predecessor, was approximately 83% owned by ENSERCH Corporation ("ENSERCH").
On August 5, 1997, the merger of ENSERCH and Texas Utilities Company and the related merger of Old EEI and Lone Star Energy Plant Operations, Inc. ("LSEPO") were completed. Under the terms of the Old EEI/LSEPO merger, LSEPO changed its name to "Enserch Exploration, Inc." ("EEI"), shares of Old EEI were automatically converted into shares of EEI on a one-for-one basis in a tax-free transaction, EEI issued 691,631 shares of common stock to ENSERCH in exchange for outstanding LSEPO common stock and ENSERCH distributed to its shareholders, on a pro rata basis, all of the shares of EEI common stock it owned.
On December 19, 1997, at a special meeting, the shareholders approved a change of the name of the Company to EEX Corporation.
2. GOING CONCERN
The Company's consolidated financial statements have been presented on the basis that it is a going concern, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. The Company has incurred recurring net losses and has a substantial working capital deficiency as of December 31, 2001. In addition, there are uncertainties relating to the Company's ability to meet all expenditure and cash flow requirements through fiscal year 2002 and early 2003, which could result in a default under the Company's revolving credit agreement. These conditions raise substantial doubt about the Company's ability to continue as a going concern. The financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classification of liabilities that may result from the outcome of these uncertainties.
The Company is seeking to alleviate these conditions by renegotiating its current revolving credit agreement that matures on June 27, 2002, raising additional capital, or through the sale or merger of the Company. The Company has a waiver until April 30, 2002 for exceeding the debt to capital ratio under this agreement. The independent auditors' modification of their opinion as to the uncertainty regarding EEX's ability to continue as a going concern is a covenant breach under the current revolving credit agreement.
One or more defaults will allow the lenders to accelerate the maturity and declare all borrowings under the current revolving credit agreement immediately payable. EEX is exploring various other options including the raising of additional capital, the sale or merger of the Company or a sale of a significant portion of its assets to repay the loan. No assurances can be provided, however, that the Company will be able to conclude a new credit agreement, obtain additional waivers of covenant breaches, raise additional capital, or sell or merge the Company. In the event these efforts are unsuccessful, EEX may seek protection from its creditors and reorganization under the Federal bankruptcy laws. In either case, EEX may not be able to continue its business as presently constituted and planned. The New York Stock Exchange may delist EEX's common stock, which could result in decreased liquidity for the common shareholders. EEX currently exceeds the minimum quantitative criteria of the Exchange for continued listing, however, no assurances can be given that the Company will continue to meet these criteria, or that the Exchange will not use other criteria or information in considering whether to institute delisting proceedings. A liquidation of assets to retire debt and preferred securities, may result in minimal to no funds remaining for the common shareholders.
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation--The consolidated financial statements are presented in accordance with generally accepted accounting principles in the United States. The consolidated financial statements include the accounts of EEX and its subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.
Critical Accounting Policies and Estimates--The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires the use of estimates and assumptions by management, many of which may significantly affect the reported amounts of assets and liabilities and related disclosure of contingent assets and liabilities as of the date of the financial statements and the reported revenues and expenses during the reporting period. Future outcomes could differ from those estimates and assumptions and materially affect reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities.
The Company believes the following critical accounting policies affect its more significant judgments and estimates used in the preparation of its consolidated financial statements:
Oil and Gas Reserve Estimates--The process of estimating quantities of proved reserves is inherently uncertain, and the reserve data included in this document are only estimates prepared by the Company. Reserve engineering is a subjective process of estimating underground accumulations of hydrocarbons than cannot be measured in an exact manner. The process relies on interpretation of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this data can vary. The process also requires certain economic assumptions regarding drilling and operating expense, capital expenditures, taxes and availability of funds. The SEC mandates some of these assumptions such as oil and gas prices and the present value discount rate.
Proved reserve estimates prepared by others may be substantially higher or lower than the Company's estimates. Because these estimates depend on many assumptions, all of which may differ from actual results, reserve quantities actually recovered may be significantly different than estimated. Material revisions to reserve estimates may be made depending on the results of drilling, testing, and rates of production.
You should not assume that the present value of future net cash flows is the current market value of the Company's estimated proved reserves. In accordance with SEC requirements, the Company based the estimated discounted future net cash flows from proved reserve on prices and costs on the date of the estimate.
The Company's rate of recording depreciation, depletion and amortization expense for proved properties is dependent on the Company's estimate of proved reserves. If these reserve estimates decline, the rate at which the Company records these expenses will increase.
Lower prices could make it uneconomic to drill and produce proved undeveloped reserves.
Estimated Value of the FPS and Pipelines--Management assessed the fair value of the FPS and Pipelines to be $70 million at yearend. This value was based upon proposals made by EEX to the Llano Field operator, competition from processing and transportation alternatives, and general estimates of the market for these assets in a third party sale. There is no established third party market for these unique assets; it is very difficult to accurately estimate what a sale would bring. In addition, the carrying value of the assets assumes an orderly disposition of the assets, which may take a significant amount of time. An immediate sale or a sale under distressed circumstances might realize much less than the carrying value of the assets. The value of the Pipelines depends on their use to transport production from the greater Llano or other areas in proximity to the Pipelines.
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
If all producers choose other transportation alternatives, the value of the Pipelines would be seriously reduced. You should not assume that management's estimate of current fair value is a definitive view of the market for these assets. The asset value could be higher or lower than this estimate depending on actual third party markets for the FPS and ultimate utility of the Pipelines. These factors are generally beyond the control of EEX.
Estimated Value of EEX's Leasehold and Investment in the Llano Area-- Management believes that this area contains substantial quantities of oil and natural gas, none of which is currently classified as proved reserves. EEX's investment in this area includes a royalty interest in the Llano Field with a carrying value of $12 million, the Jason discovery well with a carrying value of $24 million and the cost of the currently drilling Devil's Island exploration well expected to be approximately $15 million net to EEX. In addition, the Pipelines previously discussed derive their principal value from their utility as transportation for potential yet to be proved reserves in this area. Development of the Llano Field and a possible Devil's Island discovery are outside the control of EEX. Development of the Jason Field depends, in part, on the initial success of other development in the area, of which there are none currently active or approved by their owners. Some factors that may limit future development are lower commodity prices, low estimates of future recoverable reserves, unfavorable investment economics, availability of capital, and approval by co-owners. To the extent these developments do not ultimately occur, EEX may be required to impair the value of its assets in this area.
Successful Efforts Accounting--The successful efforts method of accounting is used for the Company's oil and gas operations. Under this method, acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including seismic purchases and processing, exploratory dry hole drilling costs and cost of carrying and retaining unproved properties are expensed as incurred. EEX is exposed to potential impairments if the book value of a field or field area exceeds its expected future net cash flows. This may occur if discoveries are less than anticipated, reserves are revised downward, commodity prices fall or costs increase. This determination is made either through recognition of an adverse change or a part of the annual review of all fields. The impairment of unamortized capital costs for a field or field area is reduced to an estimated fair value if it is determined that the sum of expected future net cash flows is less than the net carrying value. See Note 9.
Leasehold costs of producing properties are depleted using the unit of production method based on estimated proved oil and gas reserves quantified on the basis of their equivalent energy content. Amortization of drilling and equipment costs is based on the unit of production method using estimated proved developed oil and gas reserves quantified on the basis of their equivalent energy content. The current undiscounted cost of estimated future site restoration, dismantlement and abandonment, net of salvage, is included in the cost of productive oil and gas properties and a corresponding liability is recorded. The recorded cost is amortized on the unit of production method. Actual costs incurred for these activities are charged to the recorded liability. The sale of the Gulf of Mexico Shelf properties in December 2000 eliminated substantially all of EEX's accrued abandonment liabilities.
Depreciation of other property, plant and equipment is provided principally by the straight line method over the estimated service lives of the related assets as follows: FPS and Pipelines-20 years, leasehold improvements- remaining term of the lease, computer hardware and software- 3 to 5 years, and furniture, fixtures and other-3 to 7 years. Major improvements are capitalized, maintenance and repairs are charged to expense as incurred.
Reclassifications--Certain items in prior periods have been reclassified to be consistent with the current presentation.
Net Income (Loss) Applicable to Common Shareholders Per Share--Basic net income (loss) per share is based on the weighted average number of common shares outstanding during the period. Diluted net income (loss) per common share is based on the weighted average number of common shares and all dilutive potential common shares outstanding during the period.
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Derivative Instruments--Effective January 1, 2001, EEX adopted Statement of Financial Accounting Standards No. 133 ("SFAS No. 133"), "Accounting for Derivative Instruments and Hedging Activities," as amended, which requires that all derivative instruments be reported on the balance sheet at fair value and that changes in a derivative's fair value be recognized currently in earnings unless specific hedge criteria are met. Fair value is determined based on current market contracts with the same terms and conditions. For derivatives designated as cash flow hedges, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income (loss) and are recognized in the Consolidated Statement of Operations when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges are recognized as a charge or credit to earnings. The Company uses derivative instruments to manage exposures to commodity price risks. Hedging transactions are subject to the Company's risk management policy, which does not permit speculative positions. The Company documents relationships between hedging instruments and hedged items, and assesses and documents, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair values or cash flows associated with the hedged items. The Company may from time to time settle early derivative transactions. Gains or losses are included in other comprehensive income until they are recognized in revenues to match the underlying sales transaction being hedged. See Note 16 for additional information regarding derivative instruments.
Concentration of Credit Risk--Derivative contracts subject the Company to concentration of credit risk. The Company transacts the majority of its derivative contracts with one counterparty.
The Company had in place financial hedges and physical contracts with Enron North America Corp. at the time it filed for bankruptcy in December 2001 and recorded a reserve of approximately $3 million related to these transactions.
Stock Based Employee Compensation--The Company follows the intrinsic method of accounting for stock based compensation plans as prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" and related interpretations.
Cash and Cash Equivalents--Cash and cash equivalents include highly liquid investments with maturities of three months or less when purchased. In addition, during 1999 and early 2000, EEX classified as restricted cash, the collateral deposit required by contractual commitment under a forward purchase facility (See Note 5).
Revenue Recognition and Gas Imbalances--The Company follows the sales method of accounting for revenue recognition and gas imbalances, which recognizes over and under lifts of gas when sold, to the extent sufficient gas reserves or balancing agreements are in place. Gas sales volumes are not significantly different from the Company's share of production.
Income Taxes--Under Statement of Financial Accounting Standards No. 109 ("SFAS No. 109"), "Accounting for Income Taxes", deferred income taxes are recognized at each yearend for the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts based on tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. Valuation allowances are established when necessary to reduce the deferred tax asset to the amount expected to be realized. The Company's deferred tax asset is fully reserved as of December 31, 2001.
Impact of New Accounting Standards--On January 1, 2001, the Company adopted SFAS No. 133. This statement, as amended, requires that all derivative instruments be recorded on the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in a derivatives fair value be realized currently in earnings unless specific hedge criteria are met. The Company utilizes cash flow hedges to reduce risk of price volatility for future natural gas production. The Company's hedges qualify for hedge accounting under SFAS 133. Accounting for qualifying hedges allows derivative gains and losses to offset related results on
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
the hedged item in the statement of operations. See Note 16 for additional information regarding derivative instruments.
In 2001, the Financial Accounting Standards Board ("FASB") issued Statements of Financial Accounting Standards No. 141, "Business Combinations" ("SFAS No. 141") and No. 142, "Goodwill and Other Intangible Assets" ("SFAS No. 142"). SFAS No. 141 requires the use of the purchase method of accounting for all business combinations initiated after June 30, 2001. The adoption of this statement had no impact on the Company's consolidated results of operations and financial position. Under SFAS No. 142, goodwill and intangible assets deemed to have indefinite lives will no longer be amortized but will be subject to annual impairment tests. SFAS No. 142 is effective for fiscal years beginning after December 15, 2001. The Company will adopt the statement effective January 1, 2002. The adoption of this standard has no impact on the Company's consolidated results of operations and financial position.
In 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations" ("SFAS No. 143"). SFAS No. 143 addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The statement is effective for fiscal years beginning after June 15, 2002. The Company is currently assessing the impact, if any, of this standard.
In 2001, the FASB issued Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS No. 144"). This statement is effective for fiscal years beginning after December 15, 2001 and replaces SFAS No. 121. The Company will adopt this statement for long-lived assets and asset disposals, whether previously held and used or newly acquired on January 1, 2002. SFAS No. 144 requires that long-lived assets be measured at the lower of carrying amount or fair value less cost to sell, whether reported in continuing operations or discontinued operations. Discontinued operations will no longer be measured at net realizable value or include amounts for operating losses that have not yet occurred. This statement expands the definition of a discontinued operation from a segment of business to a component of an entity that has been disposed of or is classified as held for sale and can be clearly distinguished, operationally and for reporting purposes, from the rest of the entity. The results of operations of a component classified as held for sale shall be reported in discontinued operations in the period incurred. The Company has not yet determined what the effect of adoption, if any, will be on its consolidated results of operations and financial position.
4. MAJOR CUSTOMERS
The Company sold oil and gas production representing more than 10% of its oil and gas revenues for the year ended December 31, 2001 to El Paso Industrial Energy (25%), Shell Oil Company (13%), KN Energy (12%) and KN Midcon Texas Pipeline Operator, Inc. (11%); for the year ended December 31, 2000, to Shell Oil Company (15%) and PG&E Texas Industrial Energy L.P. (11%); and for the year ended December 31, 1999, to Shell Oil Company (30%). El Paso Industrial Energy, KN Energy, KN Midcon Texas Pipeline Operator, Inc. and PG&E Texas Industrial Energy L.P. purchase production from properties in the Onshore segment. Shell Oil Company purchases oil production from the Mudi Field in the International segment. Because alternative purchasers of oil and gas are readily available, the Company believes that the loss of any of its purchasers would not have a material adverse effect on the financial results of the Company.
5. COMMON STOCK TRANSACTIONS
Under the terms of the Company's Series B 8% Cumulative Perpetual Preferred Stock, the Company may not declare or pay any dividend or make any other distribution on its common stock, unless all dividends due upon the Series B Preferred Stock have been paid or provided for.
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Early in 1998, EEX entered into two forward purchase facilities to repurchase shares of its common stock. EEX initiated several transactions under these facilities, which allow for settlement, at EEX's option, by paying cash in exchange for physical delivery of the shares to EEX, or on a net basis in either shares of EEX common stock or in cash. As of the end of August 2000, EEX settled these two transactions by paying $8.7 million, of which $7.6 million ($5 million in 1999 and $2.6 million in 2000) was previously deposited and classified as restricted cash, for physical delivery of 796,532 shares to EEX. These shares are recorded as treasury shares in the Consolidated Balance Sheet.
6. PREFERRED STOCK TRANSACTION
On December 22, 1998, EEX entered into a Purchase Agreement ("Agreement") which provides that the Company would receive $150 million and issue to the Purchaser 1,500,000 shares of Series B 8% Cumulative Perpetual Preferred Stock and Warrants to acquire 21 million shares of the Company's Common Stock. On January 8, 1999, the transaction was closed and EEX issued the Preferred Stock and Warrants in exchange for $150 million.
Each share of Preferred Stock has a stated value of $100 and a current dividend rate of 8% per year, payable quarterly. The 8% dividend rate will be adjusted to a market rate, not to exceed 18%, after seven years or earlier occurrence of certain events including a Change of Control (as defined in the Agreement). Prior to any adjustment of the dividend rate, the Company may, at the Company's option, accrue dividends or pay them in cash, shares of Preferred Stock or shares of Common Stock. After any adjustment of the dividend rate, dividends must be paid in cash. The Preferred Stock is entitled to a liquidation preference of $100 per share plus accrued and unpaid dividends. The Preferred Stock may be redeemed, in whole but not in part, by the Company at any time for cash at the stated value plus accrued and unpaid dividends. Until any adjustment of the dividend rate, holders of the Preferred Stock will be entitled to cast an aggregate of eight million votes on matters voted upon by the Common Stock holders, and to a separate class vote on certain matters affecting the Preferred Stock. EEX has entered into a Registration Rights Agreement to register under the Securities Act of 1933, and maintain the effectiveness of the registration of the resale of the Preferred Shares, the Warrants and any Common Stock acquired by Purchaser pursuant to the Warrants. Under the terms of the Agreement, the Purchaser has the right to add a member to the Company's Board of Directors and did so in January 1999. The Purchaser may continue the membership on the Company's Board of Directors if certain conditions are maintained. In the event of a Change of Control occurring prior to the sixth anniversary of the closing of the transaction, the Purchaser has the right to exchange all or part of the Preferred Stock and Warrants proportionally for EEX Common Stock at the rate of 18.6047 shares of Common Stock for each share of Preferred Stock (and proportionate number of Warrants), provided that the Company may, under certain circumstances, pay a portion of the exchange in cash. The exercise price of the Warrants and the exchange formula related to a Change in Control may be adjusted upon the occurrence of certain events described in the anti- dilution provisions of the Warrants.
The Warrants were issued in three series, each exercisable for $12 per share of Common Stock: (a) Series A Warrants to acquire 10.5 million shares, exercisable for 10 years; (b) Series B Warrants to acquire 2.5 million shares, exercisable for 7 years, and (c) Series C Warrants to acquire 8 million shares, exercisable for 7 years. The Series A and Series B Warrants are exercisable for cash or by utilizing shares of Preferred Stock at the stated value on a gross or net basis. The Series C Warrants are exercisable only as a stock appreciation right (entitled to receive the cash difference between the exercise price and the market price of the Common Stock on the trading day prior to the date of exercise), unless the Company, prior to July 30, 2002, elects to allow the Series C Warrants to be exercised for cash or by utilizing shares of Preferred Stock at the stated value on a gross or net basis.
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The purchasers agreed to standstill provisions for 10 years that restrict their purchases of additional shares of Common Stock, prohibit sales by the purchasers of Common Stock or Warrants to any person or group that would beneficially own more than 10% (5% in the case of a competitor of the Company) of the outstanding Common Stock after the sale, prohibits the purchasers from proposing business combinations involving the Company or soliciting proxies, and limits the purchasers' aggregate voting rights to one vote less than 20% of the aggregate number of votes entitled to be cast on any matter by holders of Common Stock or any other class of capital stock.
EEX paid in-kind dividends and the Liquidation Preference on the Preferred Stock is as follows:
7. EXTRAORDINARY ITEM
In December 2001, the Company recorded an extraordinary gain of approximately $6 million pre-tax ($4 million after-tax) relating to the purchase at a discount of approximately $23 million principal amount of notes that are secured by the FPS and related infrastructure. The funds used to purchase the notes were borrowed under the Company's revolving credit facility.
The Company may consider repurchasing notes in the future at a discount but currently does not have the funds to accomplish this repurchase.
8. TESORO ACQUISITION
In December 1999, the Company acquired certain oil and gas properties and pipeline assets by purchasing stock and membership interests in corporations and limited liability companies. The Company acquired (i) all of the member interests in four limited liability companies which, together, owned all of the partnership interests of EEX E&P Company, L.P., "E&P L.P.", owner of the oil and gas assets ("Oil and Gas Interests"), and (ii) all of the issued and outstanding stock of two corporations which, together, owned all of the partnership interests in EEX Pipeline Company, L.P., which owns partnership interests in pipeline and gathering systems ("Pipeline Interests"). EEX closed the acquisition at a net cost of $219 million.
EEX Operating LLC ("EEX Operating") acquired the Pipeline Interests. The Oil and Gas Interests were acquired by EEX Reserves Funding LLC ("ERF"), a limited liability company half-owned by subsidiaries of the Company, EEX Operating (49%) and EEX Capital, Inc. (1%), and half-owned by an affiliate of Enron Corp. The Company has fully consolidated ERF, the limited liability companies owning E&P L.P. partnership interests, E&P L.P., EEX Natural Gas Company, EEX Gathering Company and EEX Pipeline Company, L.P. The affiliate of Enron Corp.'s 50% equity interest in ERF is reflected in the balance sheet as Minority Interest.
The Company entered into a call option to purchase the affiliate of Enron Corp.'s equity interest in ERF for the lesser of $5 million or the fair market value of the third party's interest, provided that the fair market value shall not exceed the equity percentage represented by the affiliate of Enron Corp.'s interest in the oil and gas reserves of E&P L.P. This call option is payable in either cash or common stock of EEX Corporation, or a combination of cash and EEX Corporation common stock, at the Company's option. The call option becomes exercisable when the forward sale described below terminates, and expires five years after it becomes exercisable.
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
E&P L.P. entered into a $105 million forward sale agreement with an affiliate of Enron Corp. for approximately 50 billion cubic feet equivalent of production from E&P L.P. through December 2004 that was prepaid upon the close of the purchase transaction (See Note 12).
At December 31, 2001, the Company has loaned approximately $150 million to ERF. The loan is in the form of a subordinated convertible note that at the Company's option is convertible into ERF units. The note does not require or permit any cash principal payment or any cash interest payment until all of E&P L.P.'s obligations under the Gas Sales Obligation have been satisfied in full. The convertible note will accrete in value at a rate of 11.5% per annum, compounded quarterly, commencing on March 31, 2000. Beginning January 1, 2005, interest will accrue at a rate of 14.5% per annum and will be payable in cash quarterly commencing on March 1, 2005 until the principal amount is paid or made available for payment.
The transaction described above has been accounted for using the purchase method of accounting and has been included in the EEX Consolidated Financial Statements since December 17, 1999.
9. ASSET IMPAIRMENTS
Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," ("SFAS No. 121") provides for the recognition of losses when events or changes in circumstances indicate that the carrying value of long-lived assets may not be realized. When there is evidence that the cost of such assets may not be realized based upon such events, changed circumstances or periodic evaluation, SFAS No. 121 requires the carrying value of the subject long-lived asset to be reduced to its fair value.
The process by which the Company assesses its oil and gas properties under SFAS No. 121 starts with a comparison of the carrying value of an asset to its estimated future undiscounted net cash flow ("Future Value"). These net cash flows are prepared by the Company. The reserves are audited by its independent petroleum consultant, Netherland, Sewell & Associates, Inc. This analysis uses a multi-year market based commodity price forecast in effect at yearend 2001. The initial prices used in this analysis for 2002 annual cash flows were $21.00 per barrel of oil and $2.742 per million British Thermal Units of gas. This analysis is generally prepared at a field level or field-group level. The fields or groups reflect the lowest level for which cash flows are reasonably and separately identifiable and for which the assets possess common operational infrastructure and geographic proximity.
Where insufficient Future Value is projected to recover the carrying value of an asset, a determination of fair value is made. Fair value is estimated for most oil and gas properties by discounting the annual net cash flows at a rate of 10% per annum. The carrying value of the asset is reduced to its estimated fair value.
Assets held for sale are carried at the lower of cost or estimated net realizable value.
At the end of the third quarter of 2001, EEX compared the carrying value of the FPS and Pipelines to the estimated returns generated from a proposal that EEX submitted to lease these assets to a third party. No impairment was indicated based upon that proposal. This original proposal was subsequently modified in the first quarter of 2002 to compete with alternative processing and transportation options available to the prospective lessees. This modified proposal significantly reduced the expected returns to EEX and generated an impairment indicator for the asset. The $152 million carrying value of the FPS and Pipelines was impaired to a fair market value of $70 million to reflect these modified proposals and values management believes could be received in an orderly sale of the assets.
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
On December 31, 2001, EEX impaired two significant onshore U.S. properties and EEX recorded a pre-tax charge of $29 million, of which $23 million was attributable to the production payment resulting from the Encogen obligation, due to lower gas prices in effect at yearend than those experienced during the prior year.
Also on December 31, 2001, EEX impaired the value of its Tuban Block assets by $16 million (pre-tax). EEX received an acceptable bid for its Indonesian subsidiaries in December 2001. This impairment reflects the difference between the agreed sales price and book value at closing, currently estimated to occur in the second quarter of 2002. The impairment also includes a discount incorporated in the sales price associated with certain receivables.
Based upon the resulting fair value at June 30, 2000, the carrying value of the Mudi Field was reduced and a pre-tax charge of $12 million for impairment was recorded for oil and gas properties located in the International business segment, primarily due to a decrease in planned production rates and the impact of higher commodity prices under the production sharing agreement.
Based upon the resulting fair values at December 31, 1999, the carrying value of long-lived assets was reduced and a pre-tax charge of $26 million for impairment was recorded for oil and gas properties located in the Onshore/Shelf business segment, primarily due to downward reserve revisions and higher abandonment cost estimates.
10. SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest, net of amounts capitalized, was $31 million in 2001, $33 million in 2000 and $12 million in 1999. There were no cash income taxes or refunds in 2001 and 2000. In 1999, there were refunds of $0.1 million.
The Statement of Cash Flows for the year ended December 31, 2001 reflects the termination of the capital lease and assumption of the secured notes as a non-cash transaction. The Statement of Cash Flows for the year ended December 31, 2001 also reflects the impact of the adoption of SFAS No. 133, which resulted in approximately a $27 million non-cash increase to shareholders' equity.
During 2000, EEX settled two forward purchase facilities to repurchase shares of its common stock by paying $8.7 million, of which $7.6 million ($5 million in 1999 and $2.6 million in 2000) was previously deposited and classified as restricted cash, for physical delivery of 796,532 shares to EEX. The Statement of Cash Flows for the year ended December 31, 2000 reflects the $5 million paid in 1999 as a non-cash transaction in 2000 when the transaction settled.
On December 17, 1999, EEX closed the Tesoro acquisition at a net cost of $215 million. The purchase price was adjusted for estimated working capital changes between the effective date and the closing date. The timing of these working capital balances resulted in an adjusted cash purchase price of $212 million as of December 31, 1999. This amount is reflected in the Consolidated Statement of Cash Flows as the Tesoro acquisition, net. In 2000, the Company made final settlement of the purchase price with Tesoro.
11. BORROWINGS AND CREDIT AGREEMENTS
EEX has a $325 million revolving credit facility with a group of banks that matures on June 27, 2002, of which $325 million was outstanding at December 31, 2001, all of which is classified as a current liability. The credit available was reduced from $350 million by amendment in February 2002. The revolving credit agreement limits, at all times, total debt, as defined, to the lesser of 60% of capitalization, as defined, or $1 billion, and prohibits liens on property except under certain circumstances. At yearend, EEX's debt to capital ratio is greater
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
than the limit of 60%. The lenders have agreed to amend the loan agreement to increase the ratio to 72% and waive the covenant breach. The amendment and waiver will expire April 30, 2002. The opinion of the independent auditors on the financial statements in this annual report contains a report modification for a going concern uncertainty. The report modification will cause a breach of another covenant. The interest rate ranges from the London Inter-Bank Offered Rate (LIBOR) plus 0.55% to 1.30% per annum, plus a facility fee of 0.20% to 0.45% per annum, depending upon the capitalization ratio. A portion of the funds available under the revolving credit line may be borrowed on a short-term basis at current money market rates.
The principal payments under the secured notes are payable in annual installments due January 2 of each year (except 2006) with the final installment due in 2009. Prepayment of the notes prior to 2006 may require the Company to pay make-whole premiums. The annual interest rate on the secured notes is 7.54%.
The following is a summary of the principal amounts by year of maturity under the revolving credit agreement and the secured notes at December 31, 2001:
The following is a summary of interest and other financing costs (in thousands):
12. GAS SALES OBLIGATION
In December 1999, E&P L.P. entered into a $105 million forward sale agreement with an affiliate of Enron Corp. for approximately 50 billion cubic feet equivalent of production from E&P L.P. through December 2004 that was prepaid upon the close of the purchase transaction. The affiliate of Enron Corp. receives an adjusted index price monthly for the committed volume. In the event production is not delivered, the obligation will be settled with a cash payment from E&P L.P. The affiliate of Enron Corp. also has a lien on the E&P L.P. oil and gas properties as security in the event the committed volumes are not delivered or cash payment is not made. The forward sale agreement also enables E&P L.P. to act as the Enron affiliate's agent to market the committed production. E&P L.P., at its discretion, may terminate the prepayment obligation by paying the affiliate of Enron Corp. a predetermined amount plus make-whole of the hedges assumed by the purchaser in the agreement. The prepayment has been recorded as a Gas Sales Obligation in the Consolidated Balance Sheet. Payments under this obligation will be amortized on the interest method through final pay out using an interest rate of 9.5%.
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
13. LEASE COMMITMENTS
During the second quarter 2001, the Company purchased the lessor's equity interest in the capital lease related to the FPS and Pipelines. The lease was terminated and EEX assumed the lessor's debt secured by the FPS and Pipelines. Refer to Note 11 concerning the debt assumed.
Amortization of assets recorded under the capital leases is included in depletion, depreciation and amortization expense.
EEX also leases buildings and office space under noncancellable operating leases that expire at various dates through December 2005.
Estimated future minimum payments under noncancellable operating leases with initial or remaining terms of one year or more at December 31, 2001 are as follows (in thousands):
Rental expenses incurred under all operating leases totaled $3.5 million, $2.7 million, and $1.8 million, in 2001, 2000, and 1999, respectively.
14. MINORITY INTERESTS
As described in Note 8, the affiliate of Enron Corp.'s 50% equity interest in ERF is reflected in the Consolidated Balance Sheet as Minority Interest.
In December 1999, the Company entered into a call option to purchase the affiliate of Enron Corp.'s equity interest in ERF for the lesser of $5 million or the fair market value of the affiliate of Enron Corp.'s interest, provided that the fair market value shall not exceed the equity percentage represented by the affiliate of Enron Corp.'s interest in the oil and gas reserves of E&P L.P. Because of this call option, the affiliate of Enron Corp.'s equity interest will not exceed $5 million, an amount reached during the third quarter of 2000. The call option is payable in either cash or common stock of EEX Corporation, or a combination of cash and EEX Corporation common stock, at the Company's option and is exercisable at any time after the termination of the forward sale between the affiliate of Enron Corp. and E&P L.P., but terminates five years after the date after the termination of the forward sale contract.
15. STOCK PLANS
The Company's Revised and Amended 1996 Stock Incentive Plan (the "1996 SIP"), provides for awards to officers, directors and key employees of restricted stock, stock options to purchase shares of common stock of EEX, or a combination of both. EEX has reserved a total of 1.3 million shares of its common stock for issuance under the 1996 SIP. Options granted under the 1996 SIP have an exercise price of not less than the fair market value of the common stock on the grant date. Options granted under the 1996 SIP become exercisable over three to seven years and expire after ten years. The terms for the release of restrictions on awards of restricted stock may be performance based, time based, or a combination of both, and each award may have different restrictions and conditions.
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The following is a summary of stock option activity under the 1996 SIP:
The following is a summary of 1996 SIP stock options outstanding at December 31, 2001:
A summary of restricted stock award activity follows:
The weighted average grant date fair value per share of restricted stock awarded during 2001, 2000 and 1999 was $4.59, $5.15 and $3.60, respectively. Fair value is equal to the common stock fair market value on the grant date.
In 1998, the Company adopted the 1998 Stock Incentive Plan ("1998 SIP") for directors, officers and eligible full-time employees. The 1998 SIP provides for awards of restricted stock, stock options and stock appreciation rights, and 2.5 million shares of common stock are reserved for issuance. Option terms and
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
restrictions on restricted stock may be set by the Compensation Committee of the Board of Directors (the "Committee"), but the exercise price may be no less than the fair market value on the date of the grant. Options granted under the 1998 SIP become exercisable over three years and expire after ten years.
The following is a summary of basic stock option activity under the 1998 SIP:
The following is a summary of 1998 SIP stock options outstanding at December 31, 2001:
A summary of restricted stock award activity follows:
The weighted average grant date fair value per share of restricted stock awarded during 2001, 2000 and 1999 was $4.55, $2.75, and $2.81, respectively. Fair value is equal to the common stock fair market value on the grant date.
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
In 1997, the Company adopted the 1997 Non-Officer Stock Option Plan ("1997 SOP") for eligible employees who are not directors or officers and non- employees. In December 1999, the 1997 SOP was amended to include restricted stock grants. The Committee may set option terms and restrictions on restricted stock, but the exercise price may be no less than the fair market value of the common stock on the grant date. EEX has reserved a total of 0.5 million shares for issuance under the 1997 SOP. Options become exercisable over three years and expire after ten years.
A summary of stock option activity under the 1997 SOP follows:
The following is a summary of 1997 SOP stock options outstanding at December 31, 2001:
A summary of restricted stock award activity follows:
The weighted average grant date fair value per share of restricted stock awarded during 2001 and 2000 was $4.59 and $2.81, respectively. Fair value is equal to the common stock fair market value on the grant date.
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
In 1996, the Company adopted the 1996 Employee Stock Option Plan ("1996 SOP"). Stock options were granted to eligible employees who were not officers or directors to purchase shares of EEX common stock that have an exercise price of not less than the fair market value of the common stock on the grant date. The shares were granted in accordance with a formula based upon salary to current employees and newly hired employees. The Plan was amended in December 1997 to allow the grant of options upon terms set by the Committee. EEX reserved a total of 0.5 million shares for issuance under this plan. Options become exercisable over three to seven years and expire after ten years. The ability to grant new options under the 1996 SOP expired December 31, 1998.
A summary of stock option activity under the 1996 SOP follows:
The following is a summary of stock options outstanding under the 1996 SOP at December 31, 2001:
On December 7, 1999, the Committee initiated an offer to certain holders of stock options with exercise prices greater than $20.00 under the 1996 SIP, the 1996 SOP and the 1997 SOP. If accepted by the holder, the offer provided that, effective December 7, 1999, the designated options would be exchanged for restricted stock granted under the 1996 SIP and the 1998 SIP. The amount of the restricted stock was computed using the Black Scholes options pricing model. The forfeiture restrictions on the restricted stock lapse as to one- third of the grant annually beginning December 7, 2000. The effect of this exchange is shown in the tables above. The restricted stock under the exchange was not issued at December 31, 1999.
Total compensation cost recognized in income for 2001, 2000 and 1999 for stock based employee compensation awards was immaterial. Had compensation cost for the Company's plans been determined based
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
on the fair value at the grant dates consistent with the method of SFAS 123, the Company's net income and earnings per share would have been reduced to the pro forma amounts indicated below (in thousands, except per share data):
The effects of applying SFAS 123 in this pro forma disclosure are not indicative of future amounts as additional awards in future years are anticipated.
Fair value of options was calculated by using the Black Scholes options pricing model using the following weighted average assumptions:
16. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
The Company's operations involve managing market risks related to changes in commodity prices and interest rates. Derivative financial instruments, specifically swaps, futures, options and other contracts, are used to reduce and manage those risks.
Commodity Hedging Activities--The Company addresses market risk by selecting instruments whose value fluctuations correlate strongly with the underlying commodity being hedged. The Company enters into swaps, options, collars and other derivative contracts to hedge the price risks associated with a portion of anticipated future oil and gas production. While the use of hedging arrangements limits the downside risk of adverse price movements, it may also limit future gains from favorable movements. Under these agreements, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at expiration or exchanged for physical delivery contracts. The Company enters into the majority of its hedging transactions with one counterparty and a netting agreement is in place with that counterparty. The Company does not obtain collateral to support the agreements but monitors the financial viability of counter-parties and believes its credit risk is minimal on these transactions. In the event of nonperformance, the Company would be exposed to price risk. The Company has some risk of accounting loss since the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the hedging transaction.
Effective January 1, 2001, the Company adopted SFAS No. 133. The cumulative effect of adopting this standard was a decrease to stockholders' equity of approximately $20 million, all of which would be reclassified into earnings during the next twelve months. Due to significant price declines during the year 2001, the net loss related to oil and gas financial hedging activities that was reclassified to revenues to match the underlying sales transaction being hedged was only $0.2 million for the year ended December 31, 2001. For the years ended December 31, 2000 and 1999, net losses related to oil and gas financial hedging activities of $20.3 million and $1.9 million, respectively, were reclassified to revenues to match the underlying sales transactions being hedged.
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
At December 31, 2001, EEX had outstanding natural gas swaps that were entered into as hedges extending through December 31, 2003 to exchange payments on 31,335 BBtu of natural gas. At December 31, 2001, the weighted average strike price and market price per MMBtu of natural gas was $3.746 and $2.960, respectively. At December 31, 2001, the Company estimated, using a NYMEX price strip as of that date, that the fair market value represented a net current asset of approximately $19.4 million and a net noncurrent asset of approximately $5.2 million and accumulated other comprehensive income of approximately $24.6 million. The Company estimates that approximately $19.4 million will be reclassified into earnings during the next twelve months and approximately $5.2 million during the year 2003. The Company recognized no ineffectiveness in 2001.
At December 31, 2001, EEX had outstanding natural gas collars that were entered into as hedges extending through June 30, 2002 to exchange payments on approximately 3 Bcf of natural gas. At December 31, 2001, the weighted average floor and ceiling strike price and market price per MMBtu of natural gas was $3.613, $5.896 and $2.631, respectively. At December 31, 2001, the Company estimated, using a NYMEX price strip as of that date, that the fair market value represented a net current asset and accumulated other comprehensive income of approximately $2.7 million. The Company estimates this amount will be reclassified into earnings during the next six months. The Company recognized no ineffectiveness in 2001.
As of December 31, 2001, the Company was not a party to any hedging contracts with respect to its current or future crude oil production.
17. INCOME TAXES
Provision (Benefit) for Income Taxes (in thousands):
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The deferred tax effect of the difference in financial accounting basis and income tax basis of EEX's assets and liabilities at December 31, 2001 and 2000 is as follows (in thousands):
- -------- Note: The current portion is included in other current assets in the consolidated balance sheets.
The Company maintains a valuation allowance to reduce the calculated deferred tax asset to net realizable value in accordance with SFAS No. 109. In 2001, EEX reduced the deferred tax asset to zero due to the uncertainty regarding the Company's liquidity and ability to replace its revolving credit facility. The anticipated earnings benefit from further realization of the additional tax basis has not been fully recognized at this time and is included in the valuation allowance of $168 million at December 31, 2001 for the Company's deferred tax asset.
As of December 31, 2001, the Company had approximately $363 million of U.S. net operating loss carryforwards ("NOLs"). The NOLs have expiration dates ranging from 2003 through 2021.
18. EMPLOYEE BENEFIT PLANS
Most of the Company's employees participate in a noncontributory defined benefit pension plan. Accrued retirement costs are funded based upon applicable requirements of federal law and deductibility for federal income tax purposes. Employees hired prior to July 1, 1989 are eligible for certain medical benefits when they retire. Medical benefits are not funded in advance.
Prior to ENSERCH's August 5, 1997 spin-off (see Note 1), EEX's cost for pension and retiree medical benefits was based on allocations from ENSERCH plans. An agreement providing for the spin-off of the pension assets to an EEX plan became the subject to a dispute between ENSERCH's successor and EEX. The dispute was resolved in January 2001. While the dispute was pending and up to June 2001, the assets remained in trust with ENSERCH's successor. Therefore, in 2000, EEX's costs for these benefit plans were based on EEX's allocated pension plan assets, employees and retirees based upon information provided by ENSERCH's successor and the pension plan assets and liabilities for accrued benefits were estimated by EEX based upon such information. In June 2001, the allocated pension plan assets were transferred to EEX's plan that was adopted effective as of January 1, 1999 and provides substantially the same benefits as provided by the ENSERCH plan. The assets are held in a trust account with investments consisting primarily of domestic equity and fixed income funds. For pension benefits, the "benefit obligation" is the projected benefit obligation. For post-retirement benefits, the "benefit obligation" is the accumulated post-retirement benefit obligation.
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Employee Benefit Plan Disclosures (in thousands):
For measurement purposes, a 5.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2001. The rate is assumed to remain at that level thereafter.
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage point change in assumed health care cost trend rates would have the following effects (in thousands):
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Investment Plan--At December 31, 2001, EEX provided a defined contribution pension plan, which permits pre-tax employee contributions and was available to substantially all employees of the Company. The Company's share of costs under the plan was $0.1 million, $0.2 million, and $0.2 million in 2001, 2000 and 1999, respectively. The Company matches up to 60% of the first 6% of employee contributions.
19. COMMITMENTS AND CONTINGENCIES
EEX is involved in a number of legal and administrative proceedings incident to the ordinary course of its business. In the opinion of management, based on the advice of counsel and current assessment, any liability to EEX relative to these ordinary course proceedings will not have a material adverse effect on EEX's operations or financial condition.
The operations and financial position of EEX continue to be affected from time to time in varying degrees by domestic and foreign political developments as well as legislation and regulations pertaining to restrictions on oil and gas production, imports and exports, natural gas regulation, tax increases, environmental regulations and cancellation of contract rights. Both the likelihood and overall effect of such occurrences on the Company vary greatly and are not predictable.
EEX has taken and will continue to take into account uncertainties and potential exposures in legal and administrative proceedings and in other areas when periodically establishing accounting reserves.
In the fourth quarter of 1998, EEX signed a contract with a major drilling company to provide and operate an offshore drilling rig for use in Deepwater drilling activities. The contract covers a basic period of three years at an average operating day rate of approximately $135,000 and commenced in July 1999. In November 2001, EEX entered into a joint venture agreement with a third party to drill the Devil's Island well, utilizing the rig at its full day rate. Upon completion of the Devil's Island well, if the rig is not used to sidetrack the Devil's Island well and EEX is not able to farmout the rig, the Company will stack the rig for the remainder of the contract. Assuming the rig is returned to EEX April 30, 2002, there will be approximately 60 days remaining under the contract at a total cost of approximately $9 million.
20. FIXED-PRICE PHYSICAL DELIVERIES
In January 2001, EEX adopted SFAS No. 133. This accounting standard requires that EEX mark to market its hedge positions and report the result as an adjustment to shareholders' equity as other comprehensive income. To mitigate the result of implementation of SFAS No. 133, in December 2000, EEX converted a portion of its existing swaps and collars into fixed-price physical delivery contracts.
During 2001, EEX delivered approximately 8 Bcf of natural gas at an average price of $2.85 per MMBtu.
Effective December 3, 2001, EEX terminated all remaining fixed-price delivery contracts due to the declaration of bankruptcy by the counterparty.
21. SUPPLEMENTARY BALANCE SHEET INFORMATION
Major accounts in certain line items of the Consolidated Balance Sheets are (in thousands):
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
22. NEW ACCOUNTING STANDARDS
In 2001, the Financial Accounting Standards Board ("FASB") issued Statements of Financial Accounting Standards No. 141, "Business Combinations" ("SFAS No. 141") and No. 142, "Goodwill and Other Intangible Assets" ("SFAS No. 142"). SFAS No. 141 requires the use of the purchase method of accounting for all business combinations initiated after June 30, 2001. The adoption of this statement had no impact on the Company's consolidated results of operations and financial position. Under SFAS No. 142, goodwill and intangible assets deemed to have indefinite lives will no longer be amortized but will be subject to annual impairment tests. SFAS No. 142 is effective for fiscal years beginning after December 15, 2001. The Company will adopt the statement effective January 1, 2002. The adoption of this standard has no impact on the Company's consolidated results of operations and financial position.
In 2001, the FASB issued Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" ("SFAS No. 143"). SFAS No. 143 addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The statement is effective for fiscal years beginning after June 15, 2002. The Company is currently assessing the impact, if any, of this standard.
In 2001, the FASB issued Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS No. 144"). This statement is effective for fiscal years beginning after December 15, 2001 and replaces SFAS No. 121. The Company will adopt this statement for long-lived assets and asset disposals, whether previously held and used or newly acquired on January 1, 2002. SFAS No. 144 requires that long-lived assets be measured at the lower of carrying amount or fair value less cost to sell, whether reported in continuing operations or discontinued operations. Discontinued operations will no longer be measured at net realizable value or include amounts for operating losses that have not yet occurred. This statement expands the definition of a discontinued operation from a segment of business to a component of an entity that has been disposed of or is classified as held for sale and can be clearly distinguished, operationally and for reporting purposes, from the rest of the entity. The results of operations of a component classified as held for sale shall be reported in discontinued operations in the period incurred. The Company has not yet determined what the effect of adoption, if any, will be on its consolidated results of operations and financial position.
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
23. SEGMENT INFORMATION
Segment information has been prepared in accordance with Statement of Financial Accounting Standards No. 131, Disclosures About Segments of an Enterprise and Related Information. EEX has determined that its reportable segments are those that are based on the Company's method of internal reporting. EEX has four reportable segments, which are primarily in the business of natural gas and crude oil exploration and production: Onshore, Deepwater Operations, Deepwater FPS/Pipelines, and International. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. EEX's reportable segments are managed separately because of their geographic locations. Financial information by operating segment is presented below (in thousands):
- -------- (a) In December 2000, the Company sold its interests in substantially all of its Gulf of Mexico Shelf production. As part of this sale, the Company retained the rights to deeper, non-producing horizons in ten of the blocks sold. All activities prior to sale date related to the Gulf of Mexico Shelf properties are included in the Onshore segment. (b) Includes primarily Cogeneration Plant Operations, General and Administrative, gains/loss on hedging and sale of assets. (c) Depletion, depreciation and amortization includes asset impairments of $127 million, $12 million and $26 million in 2001, 2000 and 1999, respectively (see Note 9). (d) Includes taxes other than income.
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
24. SUPPLEMENTARY OIL AND GAS INFORMATION (UNAUDITED)
Oil and Gas Producing Activities--The following tables set forth information relating to oil and gas producing activities of EEX. Reserve data for natural gas liquids attributable to leasehold interests owned by the Company are included in oil and condensate.
The following information is required and defined by the Financial Accounting Standards Board. The disclosure does not represent the results of operations based on historical financial statements. The disclosure excludes interest expense, corporate overhead and gains and losses from hedging (in thousands).
- -------- (a) Includes severance, ad valorem and production taxes. (b) Includes pre-tax property impairments of $127 million, $12 million and $26 million in 2001, 2000 and 1999, respectively. (c) Amount includes $35.3 million for valuation allowance on deferred tax asset for 1999.
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Oil and Gas Reserves--The following table of estimated proved and proved developed reserves of oil and gas has been prepared utilizing estimates of yearend reserve quantities audited by Netherland, Sewell & Associates, Inc., independent petroleum consultants, for December 31, 2001, 2000 and 1999. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, the reserve estimates are expected to change as additional performance data becomes available.
- -------- (a) Includes natural gas liquids of 574 MBbls for 2001, 416 MBbls for 2000, and 427 MBbls for 1999. (b) Minority Interest amounts are included in the table above. See Note 8.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities--The following table has been prepared using estimated future production rates and associated production and development costs. Continuation of economic conditions existing at the balance sheet date was assumed. Accordingly, estimated future net cash flows were computed by applying prices and contracts in effect in December to estimated future production of proved oil and gas reserves, estimating future expenditures to develop proved reserves and estimating costs to produce the proved reserves based on average costs for the year. Prices used in the computations were: Gas (per Mcf) $2.61 in 2001, $9.52 in 2000 and $2.08 in 1999; Oil (per barrel) $19.84 in 2001, $26.80 in 2000 and $23.41 in 1999, except for contractually committed volumes.
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Because reserve estimates are imprecise and changes in the other variables are unpredictable, the standardized measure should be interpreted as indicative of the order of magnitude only and not as precise amounts.
EEX CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
25. SUBSEQUENT EVENTS
Sale of Indonesian Assets--On March 11, 2002, EEX signed stock purchase agreements to sell all of the shares of two companies that own a 25% interest in the Tuban Block, onshore Java (includes Mudi Field), and a 15% interest in the Asahan Block, offshore Sumatra. These interests constitute all of EEX's assets in Indonesia. The agreements provide that the sale will be effective as of September 30, 2001 and that the purchase price of $34.5 million will be adjusted for the net cash flows received by EEX after the effective date.
The agreements are subject to customary closing conditions and regulatory approvals of Indonesian authorities. EEX anticipates that the closing will take place in the second quarter of 2002.
QUARTERLY RESULTS (UNAUDITED)
The results of operations of the Company by quarters are summarized below (in thousands, except per share data). In the opinion of the Company's management, all adjustments (consisting only of normal recurring accruals) necessary for a fair presentation have been made.
- -------- (a) Operating Income (Loss) excluding interest and taxes.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None
PART III
Item 10. Directors and Executive Officers of the Registrant
The information required in this Item is incorporated by reference from EEX's definitive proxy statement to be filed pursuant to Regulation 14A within 120 days after yearend.
Item 11. Executive Compensation
The information required in this Item is incorporated by reference from EEX's definitive proxy statement to be filed pursuant to Regulation 14A within 120 days after yearend.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The information required in this Item is incorporated by reference from EEX's definitive proxy statement to be filed pursuant to Regulation 14A within 120 days after yearend.
Item 13. Certain Relationships and Related Transactions
The information required in this Item is incorporated by reference from EEX's definitive proxy statement to be filed pursuant to Regulation 14A within 120 days after yearend.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a)-1 Financial Statements
The information required hereunder is set forth under "Report of Independent Auditors," "Consolidated Statement of Operations," "Consolidated Statement of Cash Flows," "Consolidated Balance Sheet," "Consolidated Statement of Shareholders' Equity," "Notes to Consolidated Financial Statements" and "Quarterly Results" included in Item 8.