ITEM 1: BUSINESS
GENERAL
Flores & Rucks, Inc. (the "Company") is an independent energy company engaged in the exploration, development, acquisition and production of crude oil and natural gas with operations focused primarily on the coastal onshore and shallow water offshore regions of Louisiana (the "Louisiana Gulf"), one of the most prolific oil and gas producing regions in the United States. As of December 31, 1996, the Company had estimated proved reserves of approximately 50.8 MMBbls of oil and 145.4 Bcf of natural gas, or an aggregate of approximately 75.0 MMBOE, with a Present Value of Future Net Revenues of approximately $693.5 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $532.5 million. On a BOE basis, approximately 68% of the Company's proved reserves on such date were oil. The majority of the Company's existing proved reserves are attributable to Company operated wells or leases and approximately 75% of these reserves were classified as proved developed at December 31, 1996.
In order to reduce risks and lower drilling costs, the Company uses state- of-the-art seismic evaluation technology in its exploitation and exploration activities. The seismic evaluation technology is integrated with subsurface data to improve the Company's ability to properly define the structural and stratigraphic features which potentially contain accumulation of hyrdrocarbons. As of January 16, 1997, the Company owned approximately 1,930 square miles of 3- D seismic data and approximately 22,326 linear miles of 2-D seismic data on and around its core properties.
The Company is a Delaware corporation formed in September 1994 to acquire and own 100% of the outstanding Common Stock of Flores & Rucks, Inc., a Louisiana corporation ("FRI Louisiana"). FRI Louisiana was formed in April 1992 to take advantage of opportunities to acquire and develop certain offshore properties in the Louisiana Gulf. Unless otherwise indicated, all references to the "Company" are to Flores & Rucks, Inc., a Delaware corporation, its predecessors and their respective subsidiaries.
The Company's major acquisitions to date include the acquisition from Shell Oil Company, its affiliates and subsidiaries ("Shell") of its interest in the Main Pass 69 field ("Main Pass 69") in June 1992 and its interest in the South Pass 24 and 27 fields (the "East Bay Fields", and together with the related platforms and facilities, the "East Bay Complex") in June 1993. In September 1996, the Company acquired from Mobil Oil Exploration & Producing Southeast Inc. ("Mobil") certain interests in eleven oil and gas producing fields and related production facilities primarily situated in the shallow federal waters of the central Gulf of Mexico, offshore Louisiana (the "Central Gulf Properties"). The above acquisitions coupled with the Company's successful exploration and exploitation efforts on the acquired properties have resulted in substantial increases in production and reserve growth. The Company manages its field costs by combining administrative functions relating to its properties, controlling the number of operating personnel and providing incentive compensation. Close management of operating costs combined with the increased production mentioned above have resulted in a 5% decrease to the Company's lease operating expense per BOE to $3.52 per BOE in the year ended December 31, 1996 from $3.70 per BOE in the comparable 1995 period.
OIL AND GAS MARKETING AND MAJOR CUSTOMERS
The revenues generated by the Company's operations are highly dependent upon the prices of, and demand for, oil and natural gas. The price received by the Company for its oil and natural gas production depends on numerous factors beyond the Company's control, including seasonality, the condition of the United States economy, particularly the manufacturing sector, foreign imports, political conditions in other oil-producing and natural gas-producing countries, the actions of the Organization of Petroleum Exporting Countries and domestic government regulation, legislation and policies. Decreases in the prices of oil and natural gas could have an adverse effect on the carrying value of the Company's proved reserves and the Company's revenues, profitability and cash flow. Although the Company is not currently experiencing any significant involuntary curtailment of its oil or natural gas production, market, economic and regulatory factors may in the future materially affect the Company's ability to sell its oil or natural gas production. See "Management's Discussion and Analysis of Financial Condition and Results of Operations."
The Company has a long term contract to sell all crude oil volumes produced from its East Bay fields to Shell at a price based on the highest monthly posted price of a number of principal purchasers of crude oil in the South Louisiana area. The contract expires in June 2003. The Company markets its remaining crude oil and natural gas production pursuant to short-term contracts.
Sales to Shell Oil Company, Murphy Oil USA, Inc. and Enron Capital & Trade Resources Corp. accounted for 54%, 11% and 17%, respectively, of the Company's oil and gas revenues for the year ended December 31, 1996, and 64%, 19% and 14%, respectively for the year ended December 31, 1995.
Due to the availability of other markets and pipeline connections, the Company does not believe that the loss of any single crude oil or natural gas customer would adversely affect the Company's results of operations.
COMPETITION
The oil and gas industry is highly competitive in all of its phases. The Company encounters competition from other oil and gas companies in all areas of its operations, including the acquisition of producing properties. The Company's competitors include major integrated oil and natural gas companies and numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of its competitors are large, well established companies with substantially larger operating staffs and greater capital resources than the Company's and which, in many instances, have been engaged in the energy business for a much longer time than the Company. Such companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than the Company's financial or human resources permit. The Company's ability to acquire additional properties and to discover reserves in the future will be dependent upon its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.
Capital available for investment in the oil and natural gas industry may decline significantly as a result of decreases in product prices, future changes in federal income tax laws and adverse economic conditions generally affecting the industry and the country as a whole.
OPERATING HAZARDS AND UNINSURED RISKS
The Company's operations are subject to hazards and risks inherent in drilling for and production and transportation of oil and natural gas, such as fires, natural disasters, explosions, encountering formations with abnormal pressures, blowouts, cratering, pipeline ruptures, and spills, any of which can result in loss of hydrocarbons, environmental pollution, personal injury claims, and other damage to properties of the Company and others. Additionally, the Company's oil and gas operations are located in an area that is subject to tropical weather disturbances, some of which can be severe enough to cause substantial damage to facilities and possibly interrupt production. As protection against operating hazards, the Company maintains insurance coverage against some, but not all, potential losses. The Company's coverages include, but are not limited to, operator's extra expense, physical damage on certain assets, employer's liability, comprehensive general liability, automobile, workers' compensation and loss of production income insurance. The Company believes that its insurance is adequate and customary for companies of a similar size engaged in operations similar to those of the Company, but losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have an adverse impact on the Company's financial condition and results of operations.
EMPLOYEES
As of January 1, 1997, the Company had 290 full-time employees, none of whom is represented by any labor union. Included in the total were 120 corporate employees located in the Company's Baton Rouge, Louisiana, Lafayette, Louisiana and New Orleans, Louisiana offices, as well as 170 employees who work in the Company's East Bay, Main Pass 69 and Central Gulf fields. The Company considers its relations with its employees to be good.
GOVERNMENTAL REGULATION
The Company's oil and gas exploration, production and related operations are subject to extensive rules and regulations promulgated by Federal and state agencies. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases the Company's cost of doing business and affects its profitability. Because such rules and regulations are frequently amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with such laws.
The State of Louisiana and many other states require permits for drilling operations, drilling bonds, and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging, and abandonment of such wells.
Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (the "NGPA"), and the regulations promulgated thereunder by the Federal Energy Regulatory Commission (the "FERC"). In the past, the federal government has regulated the wellhead price of natural gas. Deregulation of wellhead sales in the natural gas industry began with the enactment of the NGPA. In 1989, the Natural Gas Wellhead Decontrol Act was enacted, which amended the NGPA to remove wellhead price controls on all domestic natural gas as of January 1, 1993. While sales by producers of natural gas, and all sales of crude oil, condensate and natural gas liquids, can currently be made at uncontrolled market prices, Congress could re-enact price controls in the future.
Several major regulatory changes have been implemented by the FERC from 1985 to the present that have had a major impact on natural gas pipeline operations, services and rates and thus have significantly altered the marketing and price of natural gas. Commencing in April 1992, the FERC issued Order Nos. 636, 636-A and 636-B (collectively, "Order No. 636"), which, among other things, require each interstate pipeline company to "restructure" to provide transportation separate or "unbundled" from the sale of gas and to make available on an open and nondiscriminatory basis numerous constituent services (such as gathering services, storage services, firm and interruptible transportation services, and stand-by sales and gas balancing services) and to adopt a new ratemaking methodology to determine appropriate rates for those services. To the extent the pipeline company or its sales affiliate makes gas sales as a merchant in the future, it does so in direct competition with all other sellers pursuant to private contracts; however, pipeline companies and their affiliates were not required to remain "merchants" of gas and several of the interstate pipeline companies have become "transporters" only. Following the conclusion of individual restructuring proceedings for each interstate pipeline pursuant to Order No. 636, the FERC has approved, with modifications, all of the restructuring plans and generally accepted compliance filings implementing Order No. 636 on every interstate pipeline as of the end of 1994.
On July 16, 1996, the Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") issued its opinion on review of Order No. 636. The opinion upheld most elements of Order No. 636 including the unbundling of sales and transportation services, curtailment of pipeline capacity, implementation of the capacity release program and the mandatory imposition of straight-fixed-variable ("SFV") rate design for interstate pipeline companies. The D.C. Circuit did remand certain aspects of Order No. 636 to the FERC for further explanation including, inter alia, the FERC's decision to exempt pipelines from sharing in gas supply realignment ("GSR") costs caused by restructuring; FERC's selection of a twenty-year term matching cap for the right-of-first-refusal mechanism; the FERC's restriction on the entitlement of no-notice transportation service to only those customers receiving bundled sales service at the time of restructuring; and FERC's determination that pipelines should focus on individual customers, rather than customer classes, in mitigating the effects of SFV rate design. On February 27, 1997, the FERC issued its order on remand. The order reaffirmed the holding of Order No. 636 that pipelines should be entitled to recover 100 percent of their prudently incurred GSR costs. Moreover, since Order No. 636, few, if any, pipeline customers have been willing, or required, to commit to twenty-year contracts for existing capacity. Thus, FERC reduced the contract matching cap for the right-of-first-refusal mechanism to five years. In light of the varied post-restructuring experience with no-notice service, the FERC also decided to no longer limit a pipeline's no-notice service to its bundled sales customers at the time of restructuring. Finally, the FERC reaffirmed that pipelines should focus on individual customers, rather that customer classes, in mitigating the effects of SFV rate design. Four petitions were filed with the Supreme Court on January 27, 1997 for writ of certiorari to review those portions of the D.C. Circuit's opinion which affirmed the capacity release and
right-of-first-refusal provisions adopted in Order No. 636. Appeals of individual pipeline restructuring orders are still pending before the D.C. Circuit.
The FERC has announced its intention to reexamine certain of its transportation-related policies, including the appropriate manner in which interstate pipelines release transportation capacity under Order No. 636, and the use of market-based rates for interstate gas transmission. While any resulting FERC action would affect the Company only indirectly, the FERC's current rules and policy statements may have the effect of enhancing competition in natural gas markets by, among other things, encouraging non-producer natural gas marketers to engage in certain purchase and sale transactions. The Company cannot predict what action the FERC will take on these matters, nor can it accurately predict whether the FERC's actions will achieve the goal of increasing the competition in markets in which the Company's natural gas is sold. However, the Company does not believe that it will be treated materially differently than other natural gas producers and marketers with which it competes.
On May 31, 1995, the FERC issued a policy statement on how interstate natural gas pipelines can recover the costs of new pipeline facilities. The policy statement focused on whether projects would be priced on a rolled-in basis (rolling in the expansion costs with the existing facilities) or on an incremental basis (establishing separate cost-of services and separate rates for the existing and expansion facilities). The policy statement established a presumption in favor of rolled-in rates when the rate increase to existing customers from rolling in the new facilities is 5% or less. While this policy statement affects the Company only indirectly, the new policy should enhance competition in natural gas markets and facilitate construction of gas supply laterals. In the policy statement, the FERC contemplated that the resolution of pricing methodology would take place in individual proceedings based on the facts and circumstances of the project. The Company cannot predict what action the FERC will take in the individual proceedings.
In October of 1992 Congress passed the Energy Policy of 1992 ("Energy Policy Act"). The Energy Policy Act deemed petroleum pipeline rates in effect for the 365-day period ending on the date of enactment of the Energy Policy Act or that were in effect on the 365th day preceding enactment and had not been subject to complaint, protest or investigation during the 365-day period to be just and reasonable under the Interstate Commerce Act. The Energy Policy Act also provides that complaints against such rates may only be filed under the following limited circumstances: (i) a substantial change has occurred since enactment in either the economic circumstances or the nature of the services which were a basis for the rate; (ii) the complainant was contractually barred from challenging the rate prior to enactment; or (iii) the rate is unduly discriminatory or preferential. The Energy Policy Act further required FERC to issue rules establishing a simplified and generally applicable ratemaking methodology for petroleum pipelines, and to streamline procedures in petroleum pipeline proceedings. On October 22, 1993, the FERC responded to the Energy Policy Act directive by issuing Order No. 561, which adopts a new indexing rate methodology for petroleum pipelines. Under the new regulations, which were effective January 1, 1995, petroleum pipelines are able to change their rates within prescribed ceiling levels that are tied to the Producer Price Index for Finished Goods, minus one percent. Rate increases made pursuant to the index will be subject to protest, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline's increase in costs. The new indexing methodology can be applied to any existing rate, even if the rate is under investigation. If such rate is subsequently adjusted, the ceiling level established under the index must be likewise adjusted.
In Order No. 561, FERC said that as a general rule pipeliners must utilize the indexing methodology to change their rates. FERC indicated, however, that it was retaining cost-of-service ratemaking, market-based rates, and settlement as alternatives to the indexing approach. A cost-of-service proceeding will be instituted to determine just and reasonable initial rates for new services. A pipeline can also follow a cost-of-service approach when seeking to increase its rates above index levels for uncontrollable circumstances. A pipeline can seek to charge market-based rates if it can establish that it lacks market power. Finally, a pipeline can establish rates pursuant to settlement if agreed upon by all current shippers.
On May 10, 1996, the D.C. Circuit affirmed Order No. 561. The Court held that by establishing a general indexing methodology along with limited exceptions to indexed rates, FERC had reasonably balanced its dual responsibilities of ensuring just and reasonable rates and streamlining ratemaking through generally applicable procedures. Because of the novelty and uncertainty surrounding the indexing methodology, as well as the possibility of the use of cost-of service ratemaking and market-based rates, the Company is not able at this time to predict the effects of Order No. 561, if any, on the transportation costs associated with oil production from the Company's oil producing operations.
Under the Outer Continental Shelf Lands Act ("OCSLA"), the FERC also regulates certain activities on the Outer Continental Shelf (the "OCS"). Under OCSLA, all gathering and transporting of oil and natural gas on the OCS must be performed on an "open and non-discriminatory" basis. Consequently, the Company's gathering and transportation facilities located on the OCS must be made available to third parties. In addition, the MMS imposes regulations relating to development and production of oil and gas properties in federal waters. Under certain circumstances, the MMS may require any Company operations on federal leases to be suspended or terminated. Any such suspensions or terminations could materially and adversely affect the Company's financial condition and operations.
Certain of the Company's businesses are subject to regulation by the Federal Natural Gas Pipeline Safety Act of 1968 and other state and Federal environmental statutes and regulations.
The Oil Pollution Act of 1990 (the "OPA") imposes a variety of regulations on "responsible parties" related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. A "responsible party" includes the owner or operator of a facility or vessel, or the lessee or permittee of an area in which an offshore facility is located. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in its cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by the OPA.
The OPA also imposes ongoing requirements on a responsible party including proof of financial responsibility to cover at least some costs in a potential spill. As amended by the Coast Guard Authorization Act of 1996, OPA requires responsible parties for offshore facilities to provide financial assurance in the amount of $35 million to cover potential OPA liabilities. This amount is subject to upward regulatory adjustment up to $150 million.
ENVIRONMENTAL MATTERS
The Company's operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation is generally toward stricter standards, and this trend will likely continue. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit construction, drilling and other activities on certain lands lying within wilderness or wetlands and other protected areas; and impose substantial liabilities for pollution resulting from the Company's operations. The permits required for various of the Company's operations are subject to revocation, modification and renewal by issuing authorities. The Company believes that its operations currently are in substantial compliance with applicable environmental regulations.
Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, injunction, or both. The Company does not expect environmental compliance matters to have a material adverse effect on its financial position. It is also not anticipated that the Company will be required in the near future to expend amounts that are material to the financial condition or operations of the Company by reason of environmental laws and regulations, but because such laws and regulations are frequently changed, and may impose increasingly stricter requirements, the Company is unable to predict the ultimate cost of complying with such laws and regulations.
The following are examples of environmental, safety and health laws that potentially relate to the Company's operations:
Solid Waste. The Company's operations may generate and result in the transportation, treatment, and disposal of both hazardous and nonhazardous solid wastes that are subject to the requirements of the federal Resource Conservation and Recovery Act and comparable state and local requirements. The Environmental Protection Agency ("EPA") is currently considering the adoption of stricter disposal standards for nonhazardous waste. Further, it is possible that some wastes that are currently classified as nonhazardous, perhaps including wastes generated during pipeline, drilling and production operations, may in the future be designated as "hazardous wastes," which are subject
to more rigorous and costly disposal requirements. Such changes in the regulations may result in additional expenditures or operating expenses by the Company.
Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") and comparable state statutes, also known as "Superfund" laws, impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons for the release of a "hazardous substance" into the environment. These persons include the owner or operator of a site, and companies that transport, dispose of or arrange for the disposal of, the hazardous substances found at the site. CERCLA also authorizes the EPA, and in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the classes of responsible persons the costs they incur. Although "petroleum" is excluded from CERCLA's definition of a "hazardous substance," in the course of its ordinary operations the Company may generate other materials which may fall within the definition of a "hazardous substance." The Company may be responsible under CERCLA for all or part of the costs required to clean up sites at which such wastes have been disposed and for natural resource damages. The Company has not received any notification that it may be potentially responsible for cleanup costs under CERCLA or any comparable state law.
Air. The Company's operations may be subject to the Clean Air Act ("CAA") and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from the operations of the Company. The EPA has been developing regulations to implement these requirements. The Company may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. However, the Company does not believe its operations will be materially adversely affected by any such requirements.
Water. The Federal Water Pollution Control Act ("FWPCA") imposes restrictions and strict controls regarding the discharge of produced waters and other oil and gas wastes into navigable waters. Such discharges are typically authorized by National Pollutant Discharge Elimination System ("NPDES") permits. The FWPCA provides for civil, criminal and administrative penalties for any unauthorized discharges of oil and other hazardous substances in reportable quantities and, along with the Oil Pollution Act of 1990, imposes substantial potential liability for the costs of removal, remediation and damages. State laws for the control of water pollution also provide varying civil, criminal and administrative penalties and liabilities in the case of a discharge of petroleum or its derivatives into state waters. In addition, the Coastal Zone Management Act authorizes state implementation and development of programs of management measures for non-point source pollution to restore and protect coastal waters. As of January 1, 1997, the federal NPDES permits prohibit the discharge of produced water, and some other substances related to the oil and gas industry, from wells located in the coastal waters of Louisiana. The Louisiana Department of Environmental Quality ("LDEQ"), as administrator of the NPDES permits in Louisiana, issued on December 30, 1996, and reissued on February 28, 1997, an emergency rule to allow continued discharge of produced waters in the coastal area, subject to a zero discharge requirement by no later than December 31, 1999 for produced water being currently discharged into major deltaic passes of the Mississippi River. On February 24, 1997, LDEQ issued to the Company a compliance order allowing it to temporarily discharge produced water into Southwest Pass, a major deltaic pass of the Mississippi River. The Company has submitted to LDEQ a compliance plan for achievement of zero discharge of produced water at its East Bay Central Facility by no later than December 31, 1999. Simultaneously, the Company plans to reformat a portion of its East Bay Facilities to allow for discharge of produced water in the offshore areas, to the extent allowed by NPDES permits. Although the costs to reformat Company operations to comply with these zero discharge mandates under federal or state law may be significant, the Company believes that these costs will not have a material adverse impact on the Company's financial conditions and operations.
Protected Species. The Endangered Species Act ("ESA") seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, nor destroy or modify the critical habitat of such species. Under the ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species or its habitat. The ESA provides for criminal penalties for willful violations of the act. Other statutes which provide protection to animal and plant species and which may apply to the Company's operations which include, but are not necessarily limited to, the Marine Mammal Protection Act, the Marine Protection and Sanctuaries Act, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act.
Wetlands. Pursuant to the FWPCA, the United States Corps of Engineers, with oversight by the EPA, administers a complex program that regulates activities in wetland areas. Some of the Company's operations are in areas that have been designated as wetlands and, as such, are subject to permitting requirements. Failure to properly
obtain a permit or violation of permit terms could result in the issuance of compliance orders, restorative injunctions and a host of civil, criminal and administrative penalties. The Company believes that it is currently in substantial compliance with these permitting requirements.
Wildlife Refuges/Bird Sanctuaries. Portions of the Company's properties are located in or adjacent to federal and state wildlife refuges and bird sanctuaries. The Company's operations in such areas must comply with regulations governing air and water discharge which are more stringent than its other areas of operations. The Company has not been, and does not anticipate that it will be, materially affected by any such requirements.
Safety and Health. The Company's operations are subject to the requirements of the federal Occupational Safety and Health Act ("OSHA") and comparable state statutes. The OSHA hazard communication standard, the EPA community-right-to-know regulations under Title III of the Federal Superfund Amendment and Reauthorization Act, and similar state statutes require that certain information be organized and maintained about hazardous materials used or produced in the operations. Certain of this information must be provided to employees, state and local government authorities and citizens.
The Company incurred approximately $620,000, $694,000 and $975,000 relating to environmental compliance during 1994, 1995 and 1996, respectively.
ABANDONMENT COSTS
The Company is responsible for payment of abandonment costs on the oil and gas properties it operates. As of December 31, 1996, total abandonment costs on the Company's oil and gas properties estimated to be incurred through the year 2011 were approximately $84.0 million. Estimates of abandonment costs and their timing may change due to many factors including actual production results, inflation rates, and changes in environmental laws and regulations.
In connection with its acquisition of the East Bay Complex and Main Pass 69, the Company entered into two escrow agreements to provide for the future plugging and abandonment costs of these properties. The East Bay agreement requires the Company to make monthly deposits of $100,000 through June 30, 1998, and $350,000 thereafter until the balance in the escrow account equals $40 million unless the Company commits to the plug and abandonment of a certain number of wells in which case the increase will be deferred. The Main Pass 69 agreement requires monthly deposits of $50,000 until the balance in the escrow account equals $7.5 million. Such funds are restricted as to withdrawal by the agreement. With respect to any specifically planned plugging and abandoning operation, funds are partially released to the Company when it presents to the escrow agent the planned plugging and abandonment operations approved by the applicable governmental agency, with the balance to be released upon the presentation by the Company to the trustee of evidence from the governmental agency that the operation was conducted in compliance with applicable laws and regulations. As of December 31, 1996, the escrow balances totaled $6.3 million.
In addition, the MMS requires lessees of OCS properties to post bonds in connection with the plugging and abandonment of wells located offshore and the removal of all production facilities. Operators in the OCS waters of the Gulf of Mexico are currently required to post area wide bonds of $3 million or $500,000 per producing lease and supplemental bonds at the discretion of the MMS. On January 17, 1995, as amended May 1, 1996, the Company entered into an agreement with Planet Indemnity Company ("Planet") whereby Planet agreed to issue $11.7 million of MMS surety bonds for the Company and the Company agreed to post collateral for same in favor of Planet. The collateral includes a mortgage on the Company's federal (OCS) leases in the amount of $8.2 million, a letter of credit for $2.0 million and a pledge of certain rights to escrowed funds. The Company has posted with the MMS an area wide bond of $3.0 million and supplemental bonds totaling $17.1 million. Pursuant to a schedule previously imposed by the MMS, the Company will be required to post additional supplemental bonds up to a level of $24.6 million by January 1999, unless the Company is determined by the MMS to be exempt from such requirement due to certain financial tests. In addition, the Company is currently working with the MMS to determine the level of supplemental bonding (and the timing thereof) which will be required for some of the recently acquired Central Gulf Properties. The Company does not anticipate that the cost of any such bonding requirements will materially affect the Company's financial position. Under certain circumstances, the MMS may require any Company operations on federal leases to be suspended or terminated. Any such suspensions or terminations could have a material adverse effect on the Company's financial condition and operations.
ITEM 2:
ITEM 2: PROPERTIES
Mississippi Delta Area
The Company's Mississippi delta area (the "Mississippi Delta Area") is comprised of six Company operated fields - South Pass 1, South Pass 24, South Pass 27, South Pass 39, Main Pass 69 and Main Pass 138, as well as two non- operated fields - South Pass 41 and Main Pass 140. The Mississippi Delta Area encompasses approximately 75,458 gross leased acres in state and federal waters situated near the mouth of the Mississippi River in the Gulf of Mexico. In addition, the Company has interests in approximately 19,230 gross leased acres in the Chandeleur Sound, Blind Bay, Breton Sound and Main Pass 71/75 areas, where there are currently no producing wells.
At the core of the Mississippi Delta Area is the East Bay Complex. The East Bay Complex is a major oil production facility with daily production capacity for 70 MBbls of oil, 240 MMcf of gas and 240 MBbls of water. Within the East Bay Complex, the South Pass 24 field, discovered in 1950, has production established from 40 horizons and 460 reservoirs with cumulative production through December 31, 1996, of 321,869 MBbls of oil and 401,924 MMcf of gas. The South Pass 27 field, discovered in 1954, has production established from 40 horizons and 460 reservoirs with cumulative production through December 31, 1996, of 334,559 MBbls of oil and 798,056 MMcf of gas.
The Company owns an average 96% working interest in these fields, and for the three months ended December 31, 1996, the Mississippi Delta Area averaged daily net sales to the Company of 20.3 MBbls of oil and 56.1 MMcf of gas from 478 gross producing wells.
Central Gulf Area
The Company's Central Gulf Area (the "Central Gulf Area") is comprised of nine Company operated fields - Eugene Island 45, Eugene Island 100, Eugene Island 126, Eugene Island 128, South Marsh Island 235, South Marsh Island 243, Vermilion 215, Vermilion 273 and Ship Shoal 64, as well as two non-operated fields - South Marsh Island 269 and Vermilion 76. The Central Gulf Area consists of approximately 94,800 gross leased acres in federal waters situated in the shallow federal waters of the Central Gulf of Mexico, offshore Louisiana.
The Company owns an average 45% working interest in these fields, and for the three months ended December 31, 1996, the Central Gulf Area averaged daily net sales to the Company of 4.0 MBbls of oil and 17.4 MMcf of gas from 76 producing wells.
Effective January 3, 1997, the Company sold its interest in the South Marsh Island 269 field for $37.2 million. The South Marsh Island 269 field consisted of 27 producing wells located on approximately 11,450 gross leased acres and had average daily sales net to the Company for the three months ended December 31, 1996 of 0.8 MBbls of oil and 7.4 MMcf of gas. The Company owned an average 20% working interest in this field.
Onshore Louisiana
During 1996, the Company extended its operations to include several coastal onshore exploration projects and believes this region has been underexplored due to its complex geology and lack of 3-D seismic data. Advances in 3-D seismic acquisition techniques over the past few years have led the Company to purchase options to conduct 3-D seismic survey and explore for oil and gas on 26,945 acres in eastern Cameron Parish, Louisiana on its Mallard Bay prospect area ("Mallard Bay"). The Company is currently conducting a 70 square mile proprietary 3-D seismic survey on Mallard Bay along with its 50% working interest partner, Mobil. Over 70 prospects or leads have been identified at Mallard Bay from review of 2-D seismic and subsurface data. Separately, the Company recently acquired seismic and lease options covering 14,060 acres in its Lacassine Refuge prospect area ("Lacassine") located approximately 6 miles northwest of Mallard Bay, where it expects to begin drilling in 1997. In addition, the Company owns an average 14% working interest in 2,004 gross leased acres in the Turtle Bayou field, located in Terrebone Parish, Louisiana
OIL AND NATURAL GAS RESERVES
Presented below are the estimated quantities of proved developed and proved undeveloped reserves of crude oil and natural gas and the Present Value of Future Net Revenues (before income taxes) owned by the Company as of December 31, 1996. A portion of these reserves will be consumed by the Company in the form of fuel for its oil and gas fields. Information set forth in the following table is based upon reserve reports prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers, in accordance with the rules and regulations of the Commission. The Company includes as proven reserves, future gas production estimated by Netherland, Sewell & Associates, Inc., to be used as fuel gas. In accordance with such rules and regulations, the pretax estimate of future net revenues and the pretax present value of future net revenues was decreased by approximately $20.5 million and $18.6 million, respectively, representing the effect of hedging transactions entered into as of December 31, 1996.
(1) The Standardized Measure of Discounted Future Net Cash Flows represents the Present Value of Future Net Revenues after income taxes discounted at 10%.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the Company. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may all differ from those assumed in these estimates. Therefore, the Present Value of Future Net Revenue figures shown above should not be construed as the current market value of the estimated oil and natural gas reserves attributable to the Company's properties. The information set forth in the foregoing table includes revisions of certain volumetric reserve estimates attributable to proved properties included in the preceding year's estimates. Such revisions are the result of additional information from subsequent completions and production history from the properties involved or the result of a decrease (or increase) in the projected economic life of such properties resulting from changes in product prices.
The Company's future success depends upon its ability to find, develop or acquire additional oil and gas reserves that are economically recoverable. The proved reserves of the Company will generally decline as reserves are depleted, except to the extent that the Company conducts successful exploration or development activities or acquires properties containing proved reserves, or both. In order to increase reserves and production, the Company must continue its development and exploration drilling and recompletion programs or undertake other replacement activities. The Company's current strategy includes increasing its reserve base through acquisitions of producing properties and by continuing to exploit its existing properties. There can be no assurance, however, that the Company's planned development and exploration projects and acquisition activities will result in significant additional reserves or that the Company will have continuing success drilling productive wells at low finding and
development costs. Furthermore, while the Company's revenues may increase if prevailing oil and gas prices increase significantly, the Company's finding costs for additional reserves could also increase.
In accordance with the Commission's guidelines, the engineers' estimates of future net revenues from the Company's properties and the Present Value of Future Net Revenue thereof are made using oil and natural gas sales prices in effect as of the date of such estimates and are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. The average prices as of December 31, 1996, for the Company's properties were $25.52 per Bbl of crude oil and $4.17 per Mcf of natural gas. The foregoing prices exclude the effect of net price hedging positions. Prices for natural gas and, to a lesser extent, oil are subject to substantial seasonal fluctuations and prices for each are subject to substantial fluctuations as a result of numerous other factors. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Business--Oil and Gas Marketing and Major Customers."
PRODUCTIVE WELLS AND ACREAGE
Productive Wells
The following table sets forth the Company's existing productive wells as of December 31, 1996:
Productive wells consist of producing wells and wells capable of production, including gas wells awaiting pipeline connections. Wells that are completed in more than one producing horizon are counted as one well. Of the gross wells reported above, 49 had multiple completions.
Acreage Data
Undeveloped acreage includes leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves. A gross acre is an acre in which an interest is owned. A net acre is deemed to exist when the sum of fractional ownership interests in gross acres equals one. The number of net acres is the sum of the fractional interests owned in gross acres expressed as whole numbers and fractions thereof. The following table sets forth the approximate developed and undeveloped acreage in which the Company held a leasehold mineral or other interest at December 31, 1996.
In January 1997, the Company exercised lease options in Cameron Parish, Louisiana, which increased gross undeveloped acreage by 12,695 acres and net undeveloped acreage by 6,348 acres. In addition, the Company currently holds options covering approximately 28,893 gross acres (21,254 net) in Cameron Parish, Louisiana, and 16,727 gross and net acres in Plaquemines Parish, Louisiana, which allow the Company to conduct 3-D seismic operations on such acreage and to subsequently acquire oil and gas leases.
DRILLING ACTIVITIES
Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that new wells drilled by the Company will be productive or that the Company will recover all or any portion of its investment. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating, and other costs. The cost of drilling, completing and operating wells is often uncertain. The Company's drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond the Company's control, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment and services.
The following table sets forth the drilling activity of the Company on its properties for the years ended December 31, 1994, 1995 and 1996.
NET PRODUCTION, UNIT PRICES AND COSTS
The following table presents certain information with respect to oil and gas production and lease operating expenses attributable to all oil and gas property interests owned by the Company for the years ended December 31, 1994, 1995 and 1996.
(1) Excludes results of hedging activities. Including the effect of hedging activities, the Company's average oil price per Bbl received was $14.56, $17.27 and $19.70 in the years ended December 31, 1994, 1995 and 1996, respectively, and the average gas price per Mcf received was $1.81, $1.84 and $2.50 in the years ended December 31, 1994, 1995 and 1996, respectively.
OTHER FACILITIES
The Company currently leases approximately 8,600 square feet of office space in Baton Rouge, Louisiana, where its administrative offices are located, and approximately 42,400 square feet of office space in Lafayette,
Louisiana and approximately 1,150 square feet of office space in New Orleans, Louisiana, where the Company's technical personnel are collectively located.
The Company also leases dock and warehouse space in Venice, Louisiana and Morgan City, Louisiana.
TITLE TO PROPERTIES
The Company believes it has satisfactory title to all of its producing properties in accordance with standards generally accepted in the oil and gas industry. The Company's properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens which the Company believes do not materially interfere with the use of or affect the value of such properties. The Company's Revolving Credit Facility is secured by substantially all of the Company's oil and gas properties. The MMS and Louisiana State Mineral Board must approve all transfers of record title or operating rights on its respective leases. The MMS and Louisiana State Mineral Board approval process can in some cases delay the requested transfer for a significant period of time.
ITEM 3:
ITEM 3: LEGAL PROCEEDINGS
The Company is not a party to any material pending legal proceedings, other than ordinary routine litigation incidental to its business that management believes would not have a material adverse effect on its financial condition or results of operations.
ITEM 4:
ITEM 4: SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
ITEM 4(A): EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information concerning the executive officers of the Company:
The following biographies describe the business experience of the executive officers of the Company.
James C. Flores has served as Chairman of the Board of the Company since its inception in 1992 and as Chief Executive Officer since July 1995. From 1985 to 1992, Mr. Flores served as Vice President of FloRuxco, Inc., an oil and gas exploration company.
Richard G. Zepernick, Jr. has been with the Company since its inception, presently serving as Executive Vice President and Chief Operating Officer. Mr. Zepernick became a director of the Company in September 1994. From June 1992 until May 1993, Mr. Zepernick served as Senior Vice President and Secretary of Flores & Rucks, Inc. From 1985 to 1992, Mr. Zepernick served as General Manager of FloRuxco, Inc.
Robert L Belk has served as Senior Vice President, Chief Financial Officer and Treasurer of the Company since 1993. Mr. Belk became a director of the Company in September 1994. Prior to joining the Company, Mr. Belk worked in public accounting for H.J. Lowe & Company from 1988 to 1993. Mr. Belk is a Certified Public Accountant.
Robert K. Reeves has served as Senior Vice President, General Counsel and Secretary of the Company since May 1994. From November 1993 to May 1994, Mr. Reeves served as the Company's Vice President and General Counsel. Prior to joining the Company in 1993, he was a partner in the law firm of Onebane, Bernard, Torian, Diaz, McNamara & Abell in Lafayette, Louisiana.
David J. Morgan joined the Company in 1993 as Vice President -- Geology and became a Senior Vice President in December 1995. Mr. Morgan has 27 years of experience in the oil and gas industry. From 1983 to 1993, Mr. Morgan served as a geologist for and President of Morgan Resources, LTD., an oil and gas exploration company.
Michael O. Aldridge joined the Company in 1992 as Vice President and Controller, and became Vice President--Corporate Communications in September 1996. From 1991 until 1992, he was Vice President and Chief Financial Officer of Fleet Petroleum Partners. Mr. Aldridge is a Certified Public Accountant.
William S. Flores, Jr. joined the Company in 1993 as its Vice President -- Operations. Mr. Flores worked from 1988 to 1993 at CNG Producing Co. where he served as a Senior Operations Engineer.
Doss R. Bourgeois has served as Vice President -- Production of the Company since August 1993. From 1982 to 1993 Mr. Bourgeois worked for CNG Producing Co. until he joined the Company. His positions at CNG Producing Co. included Production Engineer, Manager Offshore Production, Supervisor Drilling Engineering, and finally Workovers & Completion/Workover Superintendent.
Clint P. Credeur has served the Company as Vice President -- Reservoir Engineering since 1993. Mr. Credeur served as a Reservoir Engineer and Special Projects Engineer with Chevron U.S.A. from November 1987 to December 1992.
James C. Flores and William S. Flores, Jr. are brothers; there are no other family relationships between any of the executive officers of the Company.
PART II
ITEM 5:
ITEM 5: MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Since March 25, 1996, the Company's Common Stock has traded on the NYSE under the symbol "FNR". The following table presents the quarterly high and low sales prices for the Common Stock on the NYSE since March 25, 1996 and, during the prior periods indicated, the high and low bid quotations in the over-the- counter market as quoted by the Nasdaq National Market since the shares became publicly traded (which quotations reflect the inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions).
As of March 21, 1997 there were approximately 153 holders of record of the Common Stock.
The Company does not anticipate paying cash dividends on its Common Stock in the foreseeable future. The Company expects that it will retain all available earnings generated by the Company's operations for the development and growth of its business. Any future determination as to the payment of dividends will be made at the discretion of t he Board of Directors of the Company and will depend upon the Company's operating results, financial condition, capital requirements, general business conditions and such other factors as the Board of Directors deems relevant. The Company's debt instruments include certain restrictions on the payment of cash dividends on the Common Stock. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources."
ITEM 6:
ITEM 6: SELECTED FINANCIAL DATA
The selected financial data set forth below for the years ended December 31, 1992, 1993, 1994, 1995 and 1996 for the Company are derived from the audited financial statements. The selected historical financial data are qualified in their entirety by, and should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the financial statements and the notes thereto included elsewhere in this Form 10-K. For additional information relating to the Company's operations, see "Business" and "Properties."
- --------
(1) Historical 1992 Company data is presented for the period from the date of formation of the Company on April 20, 1992 through December 31, 1992. Historical company data reflect the acquisitions of Main Pass 69 on June 11, 1992, the East Bay Complex on June 10, 1993, and a 12.5% minority interest thereon on December 7, 1994.
(2) Represents combined revenues and direct operating expenses for (i) all of Shell's interest in Main Pass 69 and the East Bay Complex until the acquisition by the Company of 87.5% of such interests on June 11, 1992 and June 10, 1993, respectively and (ii) the 12.5% ownership of Main Pass 69 and the East Bay Complex acquired by Franks Petroleum, Inc. on June 11, 1992 and June 10, 1993, respectively, until acquired by the Company on December 7, 1994.
(3) The amount shown for the year ended December 31, 1994 represents primarily the excess of the purchase price of the Production Payments over the book value of the Production Payments (as defined herein) liability as of December 7, 1994.
(4) The Company was formed as an S corporation under the Internal Revenue Code and, as such, all income taxes were the obligation of the Company's stockholders. Therefore, through the date of the Initial Offerings (as defined herein), no historical federal or state income tax expense has been provided for in the financial statements. In conjunction with the Initial Offerings, the Company converted to a C corporation under the Internal Revenue Code. The Company recorded a deferred tax asset of $6.3 million, offset by a valuation allowance of $6.3 million at December 31, 1994 and a deferred tax asset of $4.7 million at December 31, 1995. As a result of the reversal of the valuation allowance, the Company recorded a net income tax benefit of $4.7 million in the year ended December 31, 1995.
(5) If the Company had recognized a tax provision at statutory rates for the year ended December 31, 1995, rather than an income tax benefit, earnings per common share would have been $0.22 for such period. Earnings per share has not been presented for periods prior to or including the date of the Initial Offerings, as these amounts would not be meaningful or indicative of the ongoing entity.
(6) Earnings before interest, taxes, depreciation, depletion and amortization. EBITDA has not been reduced for the recognition of noncash revenues associated with the Production Payments. EBITDA is not intended to represent cash flow in accordance with generally accepted accounting principles and does not represent the measure of cash available for distribution. EBITDA is not intended as an alternative to earnings from continuing operations or net income.
(7) Cash flow from operating activities in 1992 and 1993 includes $36.8 million and $95.7 million, respectively, from the sale of the Production Payments. Cash flow from operating activities for the year ended December 31, 1994 was reduced by $123.6 million related to the repurchase of the Production Payments.
(8) Includes $34.3 million in the year ended December 31, 1992 related to the acquisition of Main Pass 69, $115.5 million in the year ended December 31, 1993 related to the acquisition of the East Bay Complex and $117.6 million in the year ended December 31, 1996 related to the acquisition of the Central Gulf Properties.
(9) Excludes results of hedging activities which increased (decreased) revenue recognized in the 1993, 1994, 1995 and 1996 periods by $1.2 million, $1.7 million, $(0.5) million and $(18.7) million, respectively. Including the effect of hedging activities, the Company's average oil price per Bbl received was $14.23, $14.56, $17.27 and $19.70 in the years ended December 31, 1993, 1994, 1995 and 1996, respectively, and the average gas price per Mcf received was $1.81, $1.84 and $2.50 in the years ended December 31, 1994, 1995 and 1996, respectively. The Company did not enter into any hedging activities relating to oil during 1992 or relating to gas during 1992 and 1993.
(10) Amounts represent deferred revenues recognized from the sale of the Production Payments. See Note 4 to the consolidated financial statements of the Company.
ITEM 7:
ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following is a discussion and analysis of the Company's financial condition and results of operations and should be read in conjunction with the Company's consolidated financial statements and the notes thereto included elsewhere in or incorporated by reference into this Form 10-K.
GENERAL
The Company is an independent energy company engaged in the exploration, development, acquisition and production of crude oil and natural gas with operations focused primarily on the Louisiana Gulf, one of the most prolific oil and gas producing regions in the United States. As of December 31, 1996, the Company had estimated proved reserves of approximately 50.8 MMBbls of oil and 145.4 Bcf of natural gas, or an aggregate of approximately 75.0 MMBOE, with a Present Value of Future Net Revenues of approximately $693.5 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $532.5 million. On a BOE basis, approximately 68% of the Company's proved reserves on such date were oil. The majority of the Company's existing proved reserves are attributable to Company operated wells or leases and approximately 75% of these reserves were classified as proved developed at December 31, 1996.
The Company is a Delaware corporation formed in September 1994 to acquire and own 100% of the outstanding Common Stock of FRI Louisiana. FRI Louisiana was formed in April 1992 to take advantage of opportunities to acquire and develop certain offshore properties in the Louisiana Gulf.
The Company's major acquisitions to date include the acquisition from Shell of its interest in Main Pass 69 in June 1992 and its interest in the East Bay Complex in June 1993. In September 1996, the Company acquired the Central Gulf Properties from Mobil. The above acquisitions coupled with the Company's successful exploration and exploitation efforts on the acquired properties have resulted in substantial increases in production and reserve growth. The Company manages its field costs by combining administrative functions relating to its properties, controlling the number of operating personnel and providing incentive compensation. Close management of operating costs combined with the increased production mentioned above have resulted in a 5% decrease to the Company's lease operating expense per BOE to $3.52 per BOE in the year ended December 31, 1996 from $3.70 per BOE in the comparable 1995 period.
In December 1994, the Company closed the initial public offerings (the "Initial Offerings") of 5,790,000 shares of common stock ("Common Stock") at $10 per share and $125,000,000 of 13 1/2% Senior Notes due December 1, 2004 (the "Senior Notes") and entered into the $50 million borrowing based senior revolving bank credit facility (the "Revolving Credit Facility"). In conjunction with the Initial Offerings, the Company (i) acquired 100% of the outstanding common stock of FRI Louisiana from James C. Flores, trusts for the benefit of his children and William W. Rucks, IV in exchange for a total of 8,248,000 shares of Common Stock, (ii) repurchased certain nonrecourse volumetric production payment interests (the "Production Payments"), (iii) purchased additional interests in its existing properties and (iv) repaid debt owed by the Company.
In March 1996, the Company completed a public offering of 4,500,000 shares of common stock at a price of $14.75 per share (the "Common Stock Offering"). Net proceeds to the Company from the Common Stock Offering were approximately $62.2 million, which was used primarily to repay outstanding indebtedness. In September 1996, the Company completed an offering of $160,000,000 of 9 3/4% Senior Subordinated Notes due October 1, 2006 (the "Senior Subordinated Notes") at a discount for proceeds of $159,120,000 (before offering costs). Net proceeds to the Company were approximately $154.0 million, which was used primarily to complete the acquisition of the Central Gulf Properties and to repay outstanding indebtedness.
The following table reflects certain information with respect to the Company's oil and gas properties. Sales volumes, revenues and average sales prices presented below have been segregated into those subject to Production Payments and amounts in excess of Production Payments in the applicable periods. On December 7, 1994, the Company purchased an outstanding 12 1/2% minority interest in Main Pass 69 and the East Bay Fields (the "Minority Interest"). The amounts for the year ended December 31, 1994 do not reflect the Minority Interest prior to its acquisition.
(1) Excludes results of hedging activities which increased (decreased) revenue recognized in the 1994, 1995 and 1996 periods by $1.7 million, $(0.5) million and $(18.7) million, respectively. Including the effect of hedging activities, the Company's average oil price received was $14.56, $17.27 and $19.70 in the years ended December 31, 1994, 1995 and 1996, respectively, and the average gas price received was $1.81, $1.84 and $2.50 in the years ended December 31 1994, 1995 and 1996, respectively. (2) Includes Main Pass 69 sales of 800 MBbls for the year ended December 31, 1994, subject to a long-term contract at prices averaging $1.29 per Bbl for the eleven months ended November 30, 1994. The long-term contract was terminated in connection with the Initial Offerings. See "Business--Oil and Gas Marketing and Major Customers."
(3) Volumes delivered under Production Payments were received by Enron Reserve Acquisition Corp. free and clear of severance taxes and lease operating expenses. These costs were borne in full by the Company under the terms of the Production Payments.
RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 1995 AND 1996
Revenues. The following table reflects an analysis of differences in the Company's oil and gas revenues (expressed in thousands of dollars) between the year ended December 31, 1996, and the comparable 1995 period:
The Company's total revenues increased approximately $60.5 million, or 47%, to $188.5 million for the year ended December 31, 1996, from $128.0 million for the comparable period in 1995. Production levels for the year ended December 31, 1996, increased 26% to 10,269 MBOE from 8,123 MBOE for the comparable period in 1995. The Company's average sales prices (excluding hedging activities) for oil and natural gas for the year ended December 31, 1996 were $21.58 per Bbl and $2.79 per Mcf versus $17.39 per Bbl and $1.82 per Mcf in the prior period. Revenues increased by $48.0 million due to the aforementioned production increases and by $30.5 million as a result of increased oil and gas prices. For the year ended December 31, 1996, the Company recognized additional production of 680 MBOE and related revenues of $14.8 million associated with the acquisition of the Central Gulf Properties.
For the year ended December 31, 1996, the Company's total revenues were further affected by a $18.2 million decrease in hedging revenues. In order to manage its exposure to price risks in the sale of its crude oil and natural gas, the Company from time to time enters into price hedging arrangements. See "-- Other Matters - Energy Swap Agreements." The Company's average sales prices (including hedging activities) for oil and natural gas for the year ended December 31, 1996, were $19.70 per Bbl and $2.50 per Mcf versus $17.27 per Bbl and $1.84 per Mcf in the prior period.
Lease operating expenses. Lease operating expenses decreased to $3.52 per BOE for the year ended December 31, 1996, from $3.70 per BOE in the comparable 1995 period. This decrease is primarily the result of increased production in the Company's oil and gas fields, which have substantial fixed operating costs due to the capital intensive nature of the facilities and the underutilization of capacity. For the year ended December 31, 1996, total lease operating expenses were $36.2 million, as compared to $30.0 million in the 1995 period. This increase primarily results from fluctuations in normal operating expenses, including operating expenses associated with increased production and an increase of approximately $2.8 million relating to lease operating expenses of the newly acquired Central Gulf Properties. In addition, workover expenses for the year ended December 31, 1996, increased by $1.1 million to $2.5 million, as compared to $1.4 million in the comparable 1995 period.
Severance taxes. The effective severance tax rate as a percentage of oil and gas revenues (excluding the effect of hedging activities) decreased to 5.3% in the year ended December 31, 1996, from 7.8% in the comparable 1995 period. The decrease was primarily due to increased production from new wells on federal leases, including wells located on the Central Gulf Properties, and from state leases which were exempt from state severance tax under Louisiana's severance tax abatement program.
General and administrative expenses. For the year ended December 31, 1996, general and administrative expenses were $16.2 million as compared to $11.3 million in the comparable 1995 period. This increase is primarily due to costs of increased corporate staffing associated with both an increase in drilling activities and the Company's acquisition of the Central Gulf Properties, partially offset in the 1996 period by an increase in the capitalization of a portion of the salaries paid to employees directly engaged in the acquisition, exploration and development of oil and gas properties. In addition, the Company expensed $.9 million relating to costs associated with efforts to purchase an oil and gas property outside of its United States cost center.
Depreciation, depletion, and amortization expense. For the year ended December 31, 1996, depreciation, depletion and amortization ("DD&A") expense was $74.7 million as compared to $54.1 million in the comparable 1995 period. On a BOE basis, DD&A for the year ended December 31, 1996, was $7.27 per BOE as compared to $6.66 per BOE for the year ended December 31, 1995. This variance can primarily be attributed to the Company's increased production and related current and future capital costs from the 1995 and 1996 drilling programs and the Company's purchase of the Central Gulf Properties, partially offset by the increase to proved reserves resulting from the programs and the acquisition.
Interest expense. For the year ended December 31, 1996, interest expense increased approximately $0.4 million to $18.0 million, from $17.6 million in the comparable 1995 period. This increase is primarily a result of interest expense of approximately $4.1 million related to the issuance of the Senior Subordinated Notes in September 1996. The increase was partially offset by the repayment of a portion of the Company's debt with proceeds from the Common Stock Offering and the issuance of the Senior Subordinated Notes. The increase was also partially offset by increases in the amount of interest capitalized in the 1996 period, as a result of an increase in the Company's unevaluated assets, including additional acreage and seismic data.
Income tax expense (benefit). For the year ended December 31, 1996, the Company recorded income tax expense of $12.0 million, as compared to a $4.7 million benefit in the comparable 1995 period during which the Company realized a deferred tax asset.
Net income. Due to the factors described above, net income for the year ended December 31, 1996, increased to $21.0 million, an increase of $11.1 million or 112% from net income of $9.9 million for the comparable 1995 period.
RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 1994 AND 1995
Revenues. The following table reflects an analysis of differences in the Company's oil and gas revenues (expressed in thousands of dollars) between the year ended December 31, 1995, and the comparable 1994 period:
For the year ended December 31, 1995, the Company's total revenues increased approximately $52.6 million, or 70%, to $128.0 million from $75.4 million for the comparable period in 1994. Production levels for the year ended December 31, 1995, increased 48% to 8,123 MBOE from 5,492 MBOE for the comparable period in 1994. The Company's average sales prices (excluding hedging activities) for oil and natural gas for the year ended December 31, 1995 were $17.39 per Bbl and $1.82 per Mcf, respectively, versus $14.24 per Bbl and $1.76 per Mcf, respectively, in the comparable 1994 period. Oil and natural gas volumes sold pursuant to Production Payment obligations represented approximately 35% and 52% of total sales volumes, respectively, for the year ended December 31, 1994. As a result of the repurchase of the Production Payments on December 7, 1994, the Company was able to sell all of its production at market prices in 1995 as compared to previously selling a portion of its production subject to the Production Payments at implicit contractual prices per BOE substantially below then current market prices.
For the year ended December 31, 1995, the Company recognized additional production of 950 MBOE and related revenues of $15.0 million associated with the Minority Interest purchased December 7, 1994. Of the $15.0 million, $12.4 million was primarily related to production associated with the purchased Minority Interest with the remaining $2.6 million primarily related to increased oil prices for the 1995 period.
For the year ended December 31, 1995, the Company's total revenues were further affected by a $2.2 million decrease in hedging revenues. In order to manage its exposure to price risks in the sale of its crude oil and natural gas, the Company from time to time enters into price hedging arrangements. See "-- Other Matters--Energy Swap Agreements." The Company's average sales prices (including hedging activities) for oil and natural gas for the year ended December 31, 1995, were $17.27 per Bbl and $1.84 per Mcf versus $14.56 per Bbl and $1.81 per Mcf in the prior period.
Lease operating expenses. On a BOE basis, lease operating expenses decreased 14% in the year ended December 31, 1995, to $3.70 per BOE from $4.29 per BOE in the comparable period of 1994. This decrease was primarily the result of increased production at Main Pass 69 and the East Bay Fields, which have substantial fixed operating costs due to the capital intensive nature of the facilities and the underutilization of capacity. Total lease operating expenses for the year ended December 31, 1995 were $30.0 million, as compared to $23.6 million for the comparable 1994 period. The increase was primarily related to the Company's operating expenses associated with increased production, the purchase of the Minority Interest in December 1994, an increase in painting and other preventive maintenance type programs which the Company believed to be cost effective, and increased workover costs in the 1995 period. Workover expenses increased to $1.4 million for the year ended December 31, 1995, as compared to $0.9 million for the comparable 1994 period.
Severance taxes. The effective severance tax rate as a percentage of revenues decreased to 7.8% in the year ended December 31, 1995, from 8.9% in the comparable period of 1994. This decrease was primarily due to increased production from new wells on federal leases and from state leases which were exempt from state severance tax under Louisiana's severance tax abatement program.
General and administrative expenses. General and administrative expenses per BOE decreased 26% to $1.39 per BOE in the year ended December 31, 1995 from $1.88 per BOE in the comparable period of 1994. In the year ended December 31, 1995, general and administrative expenses were $11.3 million, as compared to $10.4 million in the comparable 1994 period. The increase in general and administrative expenses was primarily due to increased corporate staffing, an increase in director and officer insurance premiums, an increase in franchise taxes and in incentive compensation. These increases were partially offset by the nonrecurring $0.9 million release and indemnity expenses incurred by the Company in the year ended December 31, 1994, a decrease in legal and other professional fees during 1995 and an increase in the capitalization of the salaries paid to employees directly engaged in the acquisition, exploration and development of oil and gas properties during 1995.
Depreciation, depletion, and amortization expense. For the year ended December 31, 1995, DD&A per BOE remained relatively unchanged at $6.66 as compared to $6.64 in the 1994 period. Total DD&A expense for the 1995 period was $54.1 million, as compared to $36.5 million for the comparable 1994 period. This variance was primarily related to the Company's increased production and related capital costs from the 1994 and 1995 drilling programs, as well as the increase in proved reserves. Also contributing to increased DD&A expense was the December 1994 acquisition of the Minority Interest.
Interest expense. Interest expense for the year ended December 31, 1995 was $17.6 million, an increase of approximately $13.1 million from $4.5 million for the comparable 1994 period. This increase was due primarily to interest expense relating to the Senior Notes and the Revolving Credit Facility. This increase was partially offset by interest that was capitalized during the year ended December 31, 1995, of $2.8 million, as compared to $0.1 million in the 1994 period.
Income tax expense (benefit). The Company was originally formed as an S corporation under the Internal Revenue Code and, as such, all income taxes were the obligation of the Company's stockholders. In conjunction with the Initial Offerings, the Company converted to a C corporation under the Internal Revenue Code. Due to a valuation allowance, the Company did not record a tax benefit for the year ended December 31, 1994. During 1995, due to drilling successes and increases in realized prices, the Company generated income from operations. At December 31, 1995, management believed it was more likely than not that the deferred tax asset would be realized. As a result, in 1995 the Company reversed the valuation allowance and recognized a tax benefit of $4.7 million.
Net income. Due to the factors described above, net income increased approximately $32.1 million from a net loss of $22.2 million for the year ended December 31, 1994 to net income of $9.9 million for the year ended December 31, 1995. For the year ended December 31, 1995, net income before the income tax benefit was $5.2 million.
LIQUIDITY AND CAPITAL RESOURCES
The following summary table reflects comparative cash flows for the Company for the years ended December 31, 1994, 1995 and 1996:
- ---------- (1) Cash flow from operating activities for the year ended December 31, 1994 was reduced by $123.6 million related to the repurchase of the Production Payments.
For the year ended December 31, 1996, net cash provided by operating activities increased by $67.1 million. This increase related primarily to an increase in revenues, partially offset by increases in lease operating expenses, severance taxes and general and administrative expenses. In addition, excluding non cash items, the Company's net working capital decreased by $14.4 million due primarily to (i) an increase in accounts payable primarily resulting from a more aggressive drilling program in 1996 as compared to 1995, and (ii) a $3.7 million deposit on assets held for resale by the Company. Net working capital was increased by increased oil and gas sales receivables due to higher prices and production during December of 1996 as compared to December of 1995.
Cash used in investing activities during the year ended December 31, 1996, increased to $293.1 million as compared to $77.7 million in the comparable 1995 period, reflecting the purchase of the Central Gulf Properties for approximately $117.6 million during 1996 and a more aggressive 1996 drilling program.
Financing activities during the year ended December 31, 1996, generated cash of $172.7 million, as compared to $18.5 million in the comparable 1995 period. The increase in cash during the 1996 period was primarily a result of the Common Stock Offering and the issuance of the Senior Subordinated Notes, which yielded net proceeds to the Company of $62.2 million and $154.0 million, respectively. This increase in cash was partially offset by the repayment of (i) a $13.0 million note to Shell Offshore, Inc. and (ii) a $32.2 million outstanding balance under the Company's Revolving Credit Facility, which is discussed below under "--Liquidity".
Capital requirements. The Company's capital investments to date have focused primarily on exploration, acquisitions and development of proved properties. The Company's expenditures for property acquisition, exploration and development for the years ended December 31, 1994, 1995 and 1996 are as follows:
The Company makes, and will continue to make, substantial capital expenditures for the acquisition, exploration, development, production and abandonment of its oil and natural gas reserves. The Company intends to finance capital expenditures related to this strategy primarily with funds provided by operations and borrowings under the Revolving Credit Facility. During the year ended December 31, 1996, the Company spent $113.4 million on exploration and development drilling and $14.0 million on 3-D seismic surveys and other geological and geophysical
costs. Included in other capital costs for the year ended December 31, 1996, is $20.0 million, that relates primarily to capital costs incurred on production facilities and flowlines. The Company is also a party to two escrow agreements which provide for the future plugging and abandonment costs associated with oil and gas properties. The first agreement, related to the East Bay Fields, requires monthly deposits of $100,000 through June 30, 1998, and $350,000 thereafter until the balance in the escrow account equals $40 million, unless the Company commits to the plugging and abandonment of a certain number of wells in which case the increase will be deferred. The second agreement, related to Main Pass 69, required an initial deposit of $250,000 and monthly deposits thereafter of $50,000 until the balance in the escrow account equals $7,500,000. As of December 31, 1996, the escrow balances totaled $6.3 million.
The Company has budgeted $200 million for 1997 drilling activities and an additional $30 million for other direct capital expenditures including lease acquisitions and seismic purchases. In addition, in the first quarter of 1997 the Company completed an acquisition of certain interests in various state leases in the Main Pass 69 field for a gross purchase price of $55.7 million. The Company's other primary capital requirements include $16.9 million for payment of interest on the Senior Notes, $15.6 million for payment of interest on the Senior Subordinated Notes and interest on any borrowings the Company may incur under the Revolving Credit Facility. The Company expects to fund its obligations with operating cash flow and borrowings under the Revolving Credit Facility.
In addition to developing its existing reserves, the Company attempts to increase its reserve base, production and operating cash flow by engaging in strategic acquisitions of oil and gas properties. During the year ended December 31, 1996, the Company spent $129.2 million on the acquisition of evaluated and unevaluated properties. In order to finance other possible future acquisitions, the Company may seek to obtain additional debt or equity financing. The availability and attractiveness of these sources of financing will depend upon a number of factors, some of which will relate to the financial condition and performance of the Company, and some of which will be beyond the Company's control, such as prevailing interest rates, oil and gas prices and other market conditions. There can be no assurance that the Company will acquire any additional producing properties. In addition, the ability of the Company to incur additional indebtedness and grant security interests with respect thereto will be subject to the terms of the Indentures (as defined herein).
Liquidity. The ability of the Company to satisfy its obligations and fund planned capital expenditures will be dependent upon its future performance, which will be subject to prevailing economic conditions, including oil and gas prices, and to financial and business conditions and other factors, many of which are beyond its control, supplemented if necessary with existing cash balances and borrowings under the Revolving Credit Facility. The Company expects that its cash flow from operations and availability under the Revolving Credit Facility will be adequate to execute its 1997 business plan. However, no assurance can be given that the Company will not experience liquidity problems from time to time in the future or on a long-term basis. If the Company's cash flow from operations and availability under the Revolving Credit Facility are not sufficient to satisfy its cash requirements, there can be no assurance that additional debt or equity financing will be available to meet its requirements.
The Revolving Credit Facility has a borrowing base of $50 million. The lenders may redetermine the borrowing base at their option once within any 12- month period as well as on scheduled redetermination dates as outlined in the Revolving Credit Facility. The borrowing base automatically reduces by an amount equal to one-sixteenth (1/16) of the borrowing base in effect on March 30, 1998, unless the Company requests and is granted a one-year deferral of such reductions.
The Company's ability to draw additional amounts on the Revolving Credit Facility is limited to the extent that Adjusted Consolidated Net Tangible Assets (as defined) minus $25 million exceeds 110% of all indenture indebtedness (as defined) excluding subordinated indebtedness (as defined). Adjusted Consolidated Net Tangible Assets is determined quarterly, utilizing certain financial information, and is primarily based on a quarterly estimate of the present value of future net revenues of the Company's proved oil and gas reserves. Such quarterly estimates utilize the most recent year end oil and gas prices and vary based on additions to proved reserves and net production. As of December 31, 1996, the Company's outstanding balance on its Revolving Credit Facility was $2.0 million (which amount represented a letter of credit associated with future abandonment obligations). The Company had remaining availability of $48.0 million under the Revolving Credit Facility as of December 31, 1996.
During 1996, the Company successfully completed a consent solicitation which resulted in the amendment of the indenture governing the Senior Notes (the "Senior Notes Indenture"). The amendment increased the Company's
ability to borrow under a revolving credit facility from $50 million to the greater of (i) $50 million and (ii) $20 million plus 20% of adjusted consolidated net tangible assets as defined in the Senior Notes Indenture.
As of February 24, 1997, the Company was in the process of amending and restating its Revolving Credit Facility and had obtained commitments from all lenders which will increase the facility size to $150 million and the borrowing base to $100 million.
Effects of Leverage. The Company is highly leveraged with outstanding indebtedness of approximately $284.1 million as of December 31, 1996. The Company's level of indebtedness has several important effects on its future operations, including (i) a substantial portion of the Company's cash flow from operations must be dedicated to the payment of interest on its indebtedness and will not be available for other purposes, (ii) the covenants contained in the Indentures (as defined herein) require the Company to meet certain financial tests, and contains other restrictions which limit the Company's ability to borrow additional funds or to dispose of assets and may affect the Company's flexibility in planning for, and reacting to, changes in its business, including possible acquisition activities and (iii) the Company's ability to obtain additional financing in the future for working capital, expenditures, acquisitions, general corporate purposes or other purposes may be impaired. Moreover, future acquisition or development activities may require the Company to alter its capitalization significantly.
The Company is required to make semi-annual interest payments of approximately $8.4 million on its Senior Notes each June 1 and December 1 through the year 2004 and semi-annual interest payments of $7.8 million on its Senior Subordinated Notes each April 1 and October 1 commencing April 1, 1997. In addition, the Company is required to make quarterly interest payments on the Revolving Credit Facility based on outstanding borrowings for the quarterly period. The Company may also, at its discretion, make principal payments on the Revolving Credit Facility.
Pursuant to the Senior Notes Indenture, the Company may not incur any Indebtedness other than Permitted Indebtedness (as defined in the Senior Notes Indenture) unless the Company's Consolidated Fixed Charge Coverage Ratio (as defined in the Senior Notes Indenture) for the four full fiscal quarters preceding the proposed new indebtedness is greater than 2.75 to 1.0 (3.0 to 1.0 if the indebtedness is incurred after December 1, 1997) after giving pro forma effect to the proposed new Indebtedness, the application of the proceeds of such Indebtedness and other significant transactions during the period. In addition, the Company's Adjusted Consolidated Net Tangible Assets (as defined in the Senior Notes Indenture) must be greater than 150% of Indebtedness after giving effect to the proposed new Indebtedness and related transactions. If the ratio of Adjusted Consolidated Net Tangible Assets to Indebtedness excluding Subordinated Indebtedness (as defined in the Senior Notes Indenture) falls below 110%, the Company may be required to buy back a portion of the Senior Notes. Pursuant to the indenture governing the Senior Subordinated Notes (the "Senior Subordinated Notes Indenture" and, together with the Senior Notes Indenture, the "Indentures"), the Company may not incur any Indebtedness other than Permitted Indebtedness (as defined in the Senior Subordinated Notes Indenture) for the four full fiscal quarters preceding the proposed new Indebtedness is greater than 2.5 to 1.0 after giving pro forma effect to the proposed new Indebtedness, the application of the proceeds of such Indebtedness and other significant transactions during the period.
In accordance with the terms of the Indentures, if the Company disposes of oil and gas assets, it must apply such proceeds to permanently pay down indebtedness other than the Senior Notes or within a specified time from the date of the asset sale, purchase additional oil and gas assets. If proceeds not applied as indicated above exceed $10 million ($15 million with respect to the Senior Subordinated Notes), the Company shall be required to offer to purchase outstanding Senior Notes and Senior Subordinated Notes or other pari passu indebtedness in an amount equal to the unapplied proceeds.
The Company believes it is currently in compliance with all covenants contained in the respective Indentures and has been in compliance since the issuance of the Senior Notes and the Senior Subordinated Notes.
The Company's ability to meet its debt service obligations and to reduce its total indebtedness will be dependent upon the Company's future performance, which will be subject to oil and gas prices, general economic conditions and to financial, business and other factors affecting the operations of the Company, many of which are beyond its control. There can be no assurance that the Company's future performance will not be adversely affected by such economic conditions and financial, business and other factors.
OTHER MATTERS
Energy swap agreements. The Company hedges certain of its production through master swap agreements ("Swap Agreements"). The Swap Agreements provide for separate contracts tied to the NYMEX light sweet crude oil and natural gas futures contracts. The Company has contracts which contain specific contracted prices ("Swaps") that are settled monthly based on the differences between the contract prices and the average NYMEX prices for each month applied to the related contract volumes. To the extent the average NYMEX price exceeds the contract price, the Company pays the spread, and to the extent the contract price exceeds the average NYMEX price the Company receives the spread. In addition, the Company has combined contracts which have agreed upon price floors and ceilings ("Costless Collars"). To the extent the average NYMEX price exceeds the contract ceiling, the Company pays the spread between the ceiling and the average NYMEX price applied to the related contract volumes. To the extent the contract floor exceeds the average NYMEX price, the Company receives the spread between the contract floor and the average NYMEX price applied to the related contract volumes. Under the terms of the Swap Agreements, each counterparty has extended the Company a $5 million line of credit for use in conjunction with its hedging activities. As of March 21, 1997, the Company's net exposure under all contracts covered by the Swap Agreements was approximately $2.6 million.
As of December 31, 1996, after giving effect to three additional oil Swaps that the Company entered into in February 1997, the Company's open forward position on its outstanding crude oil Swaps was as follows:
The Company currently has no outstanding natural gas Swaps.
As of December 31, 1996, after giving effect to three additional Costless Collars entered into through February 24, 1997, the Company's open forward position on its outstanding Costless Collars was as follows:
As a result of hedging activity under the Swap Agreement, the Company estimates that on a BOE basis, approximately 36% of its estimated 1997 production which is classified as proved reserves as of December 31, 1996, will not be subject to price fluctuation for 1997.
Currently, it is the Company's intention to commit no more than 50% of its production on a BOE basis to such arrangements at any point in time. Moreover, under the Revolving Credit Facility the Company is prohibited from committing more than 75% of its production estimates for the next 24 months to such arrangements at any point in time. As the current swap agreements expire, the portion of the Company's oil and natural gas production which is subject to price fluctuations will increase substantially, unless the Company enters into additional hedging transactions.
Despite the measures taken by the Company to attempt to control price risk, the Company remains subject to price fluctuations for natural gas and oil sold in the spot market. Prices received for natural gas sold on the spot market are volatile due primarily to seasonality of demand and other factors beyond the Company's control.
Domestic oil prices generally follow worldwide oil prices which are subject to price fluctuations resulting from changes in world supply and demand. While the price the Company receives for its oil and natural gas production has significant financial impact on the Company, no prediction can be made as to what price the Company will receive for its oil and natural gas production in the future.
Gas balancing. It is customary in the industry for various working interest partners to produce more or less than their entitlement share of natural gas from time to time. The Company's net overproduced position increased from 1,080,726 Mcf at December 31, 1995, to 2,059,954 Mcf at December 31, 1996, primarily as a result of imbalances assumed in conjunction with the acquisition of the Central Gulf Properties. During the make-up period, the Company's gas revenues will be adversely affected, limited by an unjust enrichment clause contained in the gas balancing agreement. The Company recognizes revenue and imbalance obligations under the sales method of accounting.
Environmental. The Company's business is subject to certain federal, state, and local laws and regulations relating to the exploration for, and the development production and transportation of, oil and natural gas, as well as environmental and safety matters. Many of these laws and regulations have become more stringent in recent years, often imposing greater liability on a larger number of potentially responsible parties. Although the Company believes it is in substantial compliance with all applicable laws and regulations, the requirements imposed by such laws and regulations are frequently changed and subject to interpretation, and the Company is unable to predict the ultimate cost of compliance with these requirements or their effect on its operations. Under certain circumstances, the MMS may require any Company operations on federal leases to be suspended or terminated. Any such suspensions, terminations or inability to meet applicable bonding requirements could materially and adversely affect the Company's financial condition and operations. Although significant expenditures may be required to comply with governmental laws and regulations applicable to the Company, to date such compliance has not had a material adverse effect on the earnings or competitive position of the Company. It is possible that such regulations in the future may add to the cost of operating offshore drilling equipment or may significantly limit drilling activity. See "Business--Governmental Regulation," "--Environmental Matters" and "--Abandonment Costs."
The OPA imposes ongoing requirements on a responsible party including proof of financial responsibility to cover at least some costs in a potential spill. As amended by the Coast Guard Authorization Act of 1996, OPA requires responsible parties for offshore facilities to provide financial assurance in the amount of $3.5 million to cover potential OPA liabilities. This amount is subject to upward regulatory adjustment up to $150 million.
ITEM 8:
ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Flores & Rucks, Inc. and subsidiaries:
We have audited the accompanying consolidated balance sheets of Flores & Rucks, Inc. (a Delaware corporation) and subsidiaries, as of December 31, 1996 and 1995 and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1996. 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 generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Flores & Rucks, Inc. and subsidiaries as of December 31, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
New Orleans, Louisiana February 24, 1997
FLORES & RUCKS, INC.
CONSOLIDATED BALANCE SHEETS
ASSETS
LIABILITIES AND STOCKHOLDERS' EQUITY
The accompanying notes to consolidated financial statements are an integral part of these statements.
FLORES & RUCKS, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying notes to consolidated financial statements are an integral part of these statements.
FLORES & RUCKS, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
The accompanying notes to consolidated financial statements are an integral part of these statements.
FLORES & RUCKS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes to consolidated financial statements are an integral part of these statements.
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
Organization
Flores & Rucks, Inc., a Delaware corporation (the "Company"), is an independent energy company engaged in the exploration, development, acquisition and production of crude oil and natural gas, with operations primarily in the shallow offshore regions of Louisiana. The Company was formed on September 22, 1994, to succeed to the business of Flores & Rucks, Inc., a Louisiana corporation ("FRI Louisiana") and Flores & Rucks LLC ( the "LLC"). Concurrent with the closing of the Initial Offerings (See Note 2) on December 7, 1994, FRI Louisiana was merged into a wholly owned subsidiary of the Company. Because the transaction represented the reorganization of entities under common control, the merger was treated in a manner similar to a pooling of interests.
During 1996, the Company issued 4.5 million additional shares of common stock and $160 million of 9 3/4% Senior Subordinated Notes through public offerings (See Note 2).
Hereinafter, the "Company" refers to Flores & Rucks, Inc., a Delaware corporation, its predecessors and their respective subsidiaries.
Effective January 1, 1993, FRI Louisiana issued 2,000 shares of common stock to the two stockholders of an entity which held the rights under an operating agreement to operate substantially all of FRI Louisiana's oil and gas properties. These two stockholders were deemed co-promoters of FRI Louisiana upon the exchange. As no tangible assets, or any assets with predecessor basis, were acquired by FRI Louisiana in connection with the exchange, no value was attributed to the stock issued. These shares were subsequently reacquired (See Note 7).
On December 28, 1993, FRI Louisiana transferred its interests in substantially all of its oil and gas properties to the LLC in return for an 87.5% ownership interest. The remaining 12.5% interest (the "Minority Interest") was owned by an unrelated party, Franks Petroleum, Inc. ("Franks"). FRI Louisiana proportionately consolidated its interest in LLC.
The Company is substantially leveraged. As such, a significant portion of the Company's cash flow from operations will be dedicated to debt service. As with other independent oil and gas producers, the Company is subject to numerous uncertainties and commitments associated with its operations. For example, the Company's results of operations are highly dependent upon the prices received for oil and gas. In addition, the Company will be required to make substantial future capital expenditures for the acquisition, exploration, development, production and abandonment of its oil and gas properties.
Subsidiary Guaranty
All of the Company's operating income and cash flow is generated by FRI Louisiana, a wholly owned subsidiary and the Subsidiary Guarantor of the Company. The separate financial statements of FRI Louisiana are not included herein because (i) FRI Louisiana is the only direct active subsidiary of the Company; (ii) FRI Louisiana has fully and unconditionally guaranteed the Senior Notes and the Senior Subordinated Notes (as defined in Note 2); (iii) the aggregate assets, liabilities, earnings, and equity of FRI Louisiana are substantially equivalent to the assets, liabilities, earnings and equity of the Company on a consolidated basis; and (iv) the presentation of separate financial statements and other disclosures concerning FRI Louisiana are not deemed material.
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Oil and Gas Properties
The Company's exploration and production activities are accounted for under the full cost method. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of finding oil and gas are capitalized. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, and costs related to such activities. Employee costs associated with production operations and general corporate activities are expensed in the period incurred. The Company capitalized $3,893,000, $1,643,000 and $535,000 of employee related costs directly associated with the acquisition, development or exploration of oil and gas properties during the years ended December 31, 1996, 1995 and 1994, respectively. The Company's proportionate interests in properties held under joint venture, partnership or similar arrangements are included in oil and gas properties. Transactions involving sales of reserves in place, unless unusually significant, are recorded as adjustments to oil and gas properties. Capitalized costs are limited to the sum of the present value of future net revenues discounted at 10% related to estimated production of proved reserves (which includes deferred hedge revenue) and the lower of cost or estimated fair value of unevaluated properties.
Depreciation, depletion and amortization of oil and gas properties are computed on a composite unit-of-production method based on estimated proved reserves. All costs associated with oil and gas properties, including an estimate of future development, restoration, dismantlement and abandonment costs of proved properties, are included in the computation base, with the exception of certain costs associated with unevaluated oil and gas properties. The oil and gas reserves are estimated periodically by independent petroleum engineers. The Company evaluates all unevaluated oil and gas properties on a quarterly basis to determine if any impairment has occurred. Any impairment to unevaluated properties will be reclassified as a proved oil and gas property, and thus subject to amortization if there are proved reserves associated with the related cost center. Otherwise, such impairment will be recognized in the period in which it occurs.
In March 1995, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 121 ("SFAS 121") regarding accounting for the impairment of long-lived assets. The Company adopted SFAS 121 in 1996. The effect of adopting SFAS 121 did not materially impact the Company's results of operations or financial position as of December 31, 1996.
Furniture and Equipment
Depreciation is computed using the straight-line method over the estimated useful lives of the assets, which range from 3 to 5 years.
Oil and Gas Revenue
The Company records oil and gas revenue on the sales method. As a result of this policy, the Company did not record revenues of $642,663 and $20,000 for the years ended December 31, 1996 and 1995, respectively, on gas volumes that the Company was entitled to, but which were sold by a joint owner in order to reduce previous gas imbalances. The Company recorded revenue of $376,000 during the year ended December 31, 1994, on gas volumes sold in excess of its entitled share of production. As of December 31, 1996, the Company is in a net overdelivered position of 2,059,954 Mcf, which will reduce future oil and gas revenue as the underdelivered parties
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
recoup their share of production. In connection with acquisitions, under the sales method the Company records a gas balancing liability only to the extent any net gas imbalance acquired exceeds the reserves acquired.
The Company records as oil and gas revenue the payments received from (or made to) a third party under contracts to hedge future oil and gas production (See Note 13).
Statements of Cash Flows
The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.
Earnings Per Common Share
Primary and fully diluted earnings per common share are based on the weighted average number of shares of common stock outstanding for the periods, including common equivalent shares which reflect the dilutive effect of stock options granted to certain employees and outside directors on various dates through December 31, 1996. Dilutive options that are issued during a period or that expire or are canceled during a period are reflected in both primary and fully diluted earnings per share computations for the time they were outstanding during the periods being reported.
Earnings per common share has not been presented for the Company for the year ended December 31, 1994, as this amount would not be meaningful or indicative of the ongoing entity due to the Initial Offerings (See Note 2) and related transactions.
Deferred Financing Costs
The Company has $10,543,226, net of accumulated amortization of $1,423,572, recorded as deferred financing costs as of December 31, 1996, which is related to the sale of the Senior Notes and the sale of the Senior Subordinated Notes (See Note 2) and the senior revolving bank credit facility (the "Revolving Credit Facility"),. In conjunction with the Initial Offerings (See Note 2), a balance of $1,007,114, which represented deferred financing costs associated with the term and development loans, discussed in Note 9, was expensed in the fourth quarter of 1994. Deferred financing costs are being amortized on a straight-line basis over the life of the related loans.
Fair Value of Financial Instruments
Fair value of cash, cash equivalents, accounts receivable and accounts payable approximate book value at December 31, 1996. Fair value of debt is determined based upon market value, if traded, or discounted at the estimated rate the Company would incur currently on similar debt.
Reclassifications
Certain reclassifications have been made to conform financial statement presentation between periods.
In addition, prior year oil and gas reserve quantity information in Note 15 has been restated to include estimated future reserves expected to be consumed by the Company as fuel gas.
2. INITIAL AND SUBSEQUENT PUBLIC OFFERINGS
On December 7, 1994, the Company closed initial public offerings (the "Initial Offerings") issuing 5,750,000 shares of common stock at $10 per share and $125 million of 13 1/2% Senior Notes due December 1, 2004
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(the "Senior Notes"), and concurrently exchanged the Enron Option (See Note 4) and $1,000 for one million shares of common stock. Additionally, the Company acquired the Franks interest (for $6.0 million cash) and the LLC was merged into the Company. Also, concurrent with the closing of the Initial Offerings, the Company acquired the production payment obligations for East Bay Complex and Main Pass 69 (See Notes 3 and 4), repaid the term loan and development loans (See Note 9) and paid off notes to current and former stockholders (See Note 7).
In January 1995, the Company issued an additional 40,000 shares of common stock relating to the exercise of the underwriters over allotment option. Net proceeds to the Company from the issuance of these shares was $372,000.
On March 19, 1996, the Company completed a public offering of 4,500,000 shares of common stock at a price of $14.75 per share (the "Offering"). Net proceeds of the Offering were approximately $62.2 million, of which $15.4 million was used to repay a note payable to Shell Offshore, Inc. and approximately $33.0 million was used to repay indebtedness under the Revolving Credit Facility.
On September 26, 1996, the Company completed an offering of $160,000,000 of 9 3/4% Senior Subordinated Notes at a discount (the "Senior Subordinated Notes") for proceeds of $159,120,000 (before offering costs). The principal is due October 1, 2006. Interest on the notes will be payable semi-annually in arrears on April 1 and October 1 of each year, commencing April 1, 1997. Net proceeds to the Company were approximately $154 million, which was used primarily to complete the acquisition of the Central Gulf Properties (See Note 3) and to repay outstanding indebtedness of $25.1 million under the Company's Revolving Credit Facility.
3. INVESTMENT IN OIL AND GAS PROPERTIES
On June 11, 1992, the Company acquired a producing oil and gas property ("Main Pass 69") from Shell Oil Company, its affiliates and subsidiaries ("Shell"), for $39.2 million. On June 10, 1993, the Company acquired a second producing property (the "East Bay Complex") from Shell for $131.9 million. Concurrent with these acquisitions, the Company assigned overriding royalty interests burdening one-eighth of the working interests to a company owned by a stockholder for services rendered in connection with the acquisitions. In addition, the Company sold to Franks the one-eighth working interests subject to the override in return for the assumption of one-eighth of the volumetric production payment liabilities related thereto (See Note 4) and, for the East Bay Complex, one-eighth of a note payable to Shell (Note 9). In addition, see Note 4 for a discussion of the sale of an option to Enron Financial Corporation related to the East Bay Complex.
On December 7, 1994, the Company acquired Franks' interest in the LLC for $6 million and recorded the acquisition using the purchase method. Included in the purchase the Company acquired cash totaling $23,000, other current assets totaling $56,000, the Minority Interest's share of a plug and abandonment escrow totaling $269,000 and other assets totaling $124,000. In addition, the Company assumed accrued interest payable of $53,000, notes payable on JEDI loans (as defined in Note 9) of approximately $4.4 million, deferred hedge revenue of $85,000, an approximate $1.8 million liability owed to the Company and deferred production payment revenues of approximately $15.5 million, as well as the assumption of a $710,000 liability owed to the LLC. The Company recorded an increase in the full cost pool of $28.1 million. The Company allocated the purchase price between evaluated and unevaluated properties based on estimated relative fair market value.
On September 26, 1996, the Company acquired from Mobil Oil and Producing Southeast, Inc. ("Mobil"), certain interests in eleven oil and gas producing fields and related production facilities primarily situated in the shallow federal waters of the central Gulf of Mexico, offshore Louisiana, (the "Central Gulf Properties") for approximately $117.6 million. The Company financed the acquisition with proceeds from the issuance of the Senior Subordinated Notes (See Note 2). At December 31, 1996, one of the eleven Central Gulf Properties was reclassified as "Assets held for resale". The subject property was sold on January 3, 1997, for $37.2. No gain or loss was recognized on the sale.
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The following pro forma information gives effect to the acquisition of the Central Gulf Properties by the Company as if it had occurred on January 1, 1995.
The following table discloses certain financial data relative to the Company's oil and gas producing activities, substantially all of which are located in the offshore waters of the continental United States.
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The following table discloses financial data associated with capitalized unevaluated costs as of December 31, 1996.
4. PRODUCTION PAYMENTS
Concurrent with the Main Pass 69 and East Bay Complex acquisitions, the Company sold to Enron Reserve Acquisition Corp. ("ERAC") nonrecourse volumetric production payment interests of approximately $36.7 million and $95.7 million, respectively, net of the amounts assumed by Franks.
The Company deferred the revenue associated with the sale of these production payment interests because a substantial obligation for future performance existed. Under the terms of the sales, the Company was obligated to deliver the production payment volumes free and clear of lease operating expenses, production taxes, plugging and abandonment and other capital costs. The deferred revenue was amortized on the unit-of-production method and recognized as oil and gas revenues as the associated hydrocarbons were delivered. In addition, under separate agreements, the Company was required to sell all excess production over production payment volumes from the subject properties to an affiliate of ERAC during the same periods. Sales from the East Bay Complex were made at market prices, whereas sales from Main Pass 69 were made at the affiliate's posted price, which during the eleven months ended November 30, 1994 was approximately $1.29 per barrel below other buyers' postings for similar crude oil. Sales from Main Pass 69 for December 1994 were made to the affiliate at market prices.
In connection with the East Bay Complex production payment, Enron Finance Corp. ("Enron") obtained from the Company the right to acquire during a ten-year period commencing January 1, 1996 (or upon a registration of securities), at a nominal cost, a one-eighth working interest in the East Bay Complex or a 9% interest in LLC (the "Enron Option"). If the working interest was acquired, it would have been burdened by its share of the production payment. For accounting purposes, the total proceeds received by the Company from ERAC related to the East Bay Complex production payment were allocated between deferred revenue from the sale of the production payment interest ($95.7 million) and a reduction in the full cost pool resulting from the sale of a portion of the Company's interest in East Bay Complex ($7.5 million) based upon the relationship of one- eighth of post-January 1, 1996 reserves to total reserves, as determined at the date of acquisition. The production payment volumes attributed to this interest were 401 MBbls and 1,369 MMcf. In December 1994 Enron contributed its Enron Option and $1,000 in exchange for one million shares of the Company's common stock. As a result of the exchange, the Company recorded a $7.5 million increase to oil and gas properties as well as an increase of $7.5 million for the related production payment obligation, which were originally reduced from the respective accounts.
Concurrent with the Initial Offerings, the Company repurchased the production payment interests. The cost to acquire the production payment liability exceeded its book value by approximately $15.7 million. This excess represented the difference between the amount paid and the book value of the production payment liability as of December 7, 1994. This excess was recorded as an expense in the period acquired.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
5. RESTRICTED DEPOSITS
The Company, as the operator of the acquired oil and gas properties, is a party to two escrow agreements, the first, related to East Bay, requires monthly deposits of $100,000 through June 30, 1998, and $350,000 thereafter until the balance in the escrow account equals $40 million unless the Company commits to the plug and abandonment of a certain number of wells in which case the increase will be deferred. The second agreement, related to Main Pass, required an initial deposit of $250,000 and monthly deposits thereafter of $50,000 until the balance in the escrow account equals $7,500,000. These deposits are to provide for the future plugging and abandonment costs associated with the oil and gas properties. Such funds are restricted as to withdrawal by the agreements. With respect to any specifically planned plugging and abandoning operation, funds are partially released when the Company presents to the escrow agent the planned plugging and abandoning operations approved by the applicable governmental agency, with the balance released upon the presentation by the Company to the escrow agent of evidence from the governmental agency that the operation was conducted in compliance with applicable laws and regulations. The escrow agent for both agreements is an unrelated financial institution. As of December 31, 1996 and 1995, the escrow balances were approximately $6.3 million and $4.3 million, respectively.
6. INCOME TAXES
The Company was formed as an S corporation under the Internal Revenue Code and, as such, all income taxes were the obligation of the Company's stockholders. Therefore, through December 7, 1994, no historical federal or state income tax expense has been provided for in the financial statements. In conjunction with the Initial Offerings, the Company converted to a C corporation under the Internal Revenue Code.
The Company has adopted Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" ("SFAS 109"). SFAS 109 requires deferred tax liabilities or assets be recognized for the anticipated future tax effects of temporary differences that arise as a result of the difference in the carrying amounts and the tax bases of assets and liabilities. The components of the income tax provision (benefit) for each of the periods presented are as follows:
Deferred income taxes are provided to reflect temporary differences in the basis of net assets for income tax and financial reporting purposes. The tax effected temporary differences and tax loss carryforwards which comprise deferred taxes are as follows:
A valuation allowance is provided for that portion of the asset for which it is deemed more likely than not that it will not be realized. Due to the Company's losses in 1994 and the substantial volatility in oil and gas prices,
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
management provided a valuation allowance for the entire deferred tax asset at December 31, 1994. During the second half of 1995, due to drilling successes and increases in oil and gas prices, the Company generated income from operations. Based upon estimates, management believed it was more likely than not that the deferred tax asset as of December 31, 1995 would be realized, and thus eliminated the valuation allowance in 1995.
The principal reasons for the differences between income taxes computed at the statutory federal income tax rate and the income tax provision (benefit) are as follows:
At December 31, 1996, the Company had regular tax net operating loss carryforwards of approximately $29.0 million and alternative minimum tax net operating loss carryforwards of approximately $12.6 million. These loss carryforward amounts will expire during the years 2009 through 2111.
7. STOCKHOLDERS' EQUITY
In February 1994, the Company agreed to re-acquire 1,000 shares of stock from a former stockholder discussed in Note 1, for a total of $10.0 million (two notes in the amount of $5 million each). The notes bore interest at 8% and were paid on March 1, 1995. In June 1994, the Company agreed to reacquire 1,000 shares of stock from the other former stockholder discussed in Note 1 for $8.7 million, $5.0 million of which was paid in June 1994, and the remainder of which was paid with the proceeds of the Initial Offerings.
8. RELATED PARTY TRANSACTIONS
Effective July 1, 1994, the Company acquired indirectly from stockholders various overriding royalty interests for $1.2 million.
During 1994, the Company forgave $500,000 due from two stockholders. The amounts related to promissory notes which bore interest at 8% per annum and were due upon demand, and if no demand, then by December 31, 1994. On March 1, 1995, $250,000 due from a former stockholder was received.
In July 1994, the Company purchased a portion of the overriding royalty interests previously assigned to an affiliate of a stockholder for $3 million (See Note 3). At that time, two stockholders loaned the Company $5 million to make a payment to a former stockholder (See Note 7). In September 1994, the stockholder affiliate exercised its right to repurchase the overriding royalty interest from the Company for $3 million and the Company repaid $3
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
million of the loans by the stockholders. The Company utilized a portion of the net proceeds of the Initial Offerings to repay the remaining $2 million in loans to stockholders.
During 1994, the Company contracted with oilfield service companies previously owned by current and former stockholders. The total amounts paid for these services was $1,091,152 during the first six months of 1994 (at June 30, 1994, the stockholders assigned their interest in such companies to a former stockholder). The Company believes that the cost of such services would have been substantially similar to costs that would have been charged by unaffiliated third parties for such services.
During 1994, the Company was assigned an oil and gas prospect from an officer of the Company, who retained an overriding royalty interest. In addition, the Company paid the officer $50,000 for services rendered in connection therewith as well as $108,000 to a third party for acquisition of the leases. During 1996, the Company purchased a working interest ownership in a field where the Company had an existing working interest from the officer for $188,026.
During 1996, 1995 and 1994, the Company paid $1,430,089, $1,041,088 and $635,960, respectively, to an affiliate of a stockholder associated with an overriding royalty interest owned by it. In addition, during 1995 and 1994, the Company paid $4,753 and $124,376, respectively, with respect to oil and gas properties previously owned by the affiliate. These amounts are included in accounts receivable from stockholders at December 31, 1995 and 1994, and were repaid in full on March 27, 1996.
During 1994, the Company obtained a loan from Union Planters Bank in connection with the purchase of a seaplane. During 1995, Mr. Flores was named a member of the Board of Directors of that bank. The loan was made to the Company for the amount of $132,500, bearing interest at the Wall Street Prime rate. Principal and interest payments were payable monthly, with the balance due on February 10, 1997. The outstanding principal balance plus accrued interest at December 31, 1996, was $92,133. On February 10, 1997, the balance of the loan was paid in full. In addition, Union Planters Bank is a member of the syndicate under the Revolving Credit Facility. Effective December 31, 1996, Mr. Flores resigned as a member of the Board of Directors of Union Planters Bank.
Effective November 1, 1995, the Company entered into a consulting agreement for geological services with a party related to an officer of the Company. The original term of this agreement expired on October 31, 1996, and the term was extended for a one year period. In 1995, the Company paid $5,200 pursuant to the agreement as well as $5,000 for other miscellaneous geological consulting services received. In addition, in 1995 the Company paid $50,000 for services rendered in connection with an oil and gas prospect assigned to it by such party. In 1996, the Company paid $110,565 relating to the agreement.
On September 13, 1996, the Company entered into a retainer agreement for legal services to be rendered by a law firm owned by a party related to an officer of the Company. This agreement is automatically extended for successive 3 month periods unless terminated by one of the parties. Legal fees paid by the Company relating to this retainer during 1996 totaled $25,196.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
9. LONG-TERM DEBT
The Revolving Credit Facility was committed for up to a five-year period. The Revolving Credit Facility had an initial borrowing base of $50 million. Chase Manhattan Bank, N.A. (the "Agent"), with the concurrence of majority lenders (as defined in the $50,000,000 Credit Agreement among Flores & Rucks, Inc. and Chase Manhattan Bank, N.A.) (the "Credit Agreement"), can redetermine the borrowing base at its option once within any 12-month period as well as on scheduled redetermination dates as outlined in the Credit Agreement. The borrowing base automatically reduces by an amount equal to one-sixteenth (1/16) of the borrowing base in effect on each quarter beginning March 31, 1998, unless the Company requests and is granted a one-year deferral of such reductions. In addition, the borrowing base may be reduced if the Company sells a portion of its oil and gas properties. As of December 31, 1996, the borrowing base under the Revolving Credit Facility remained at $50 million.
As of February 24, 1997, the Company was in the process of amending and restating its Revolving Credit Facility and had obtained commitments from all lenders which will increase the facility size to $150 million and the borrowing base to $100 million.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The Company's ability to draw additional amounts on the Revolving Credit Facility is limited to the extent that adjusted consolidated net tangible assets (as defined in the Credit Agreement) minus $25 million exceeds 110% of all indenture indebtedness (as defined in the Credit Agreement), excluding subordinated indebtedness. Adjusted consolidated net tangible assets is determined quarterly, utilizing certain financial information, and is primarily based on a quarterly estimate of the present value of future net revenues of the Company's proved oil and gas reserves. Such quarterly estimates utilize the most recent year end oil and gas prices and vary based on additions to proved reserves and net production. As of December 31, 1996, the Company's outstanding balance was $2.0 million, all of which represented letters of credit, primarily associated with bonding for future abandonment obligations, and thus the Company had remaining availability of $48.0 million.
At the Company's option, borrowings under the Revolving Credit Facility bear interest either at the base rate (the higher of the federal funds rate plus 0.5% per annum or the Agent's prime commercial lending rate) or the London Interbank Offered Rate ("LIBOR"), in each case plus the applicable margin. The applicable margin will be from 125 to 175 basis points for LIBOR loans and from zero to 50 basis points for the base rate loans.
The loan agreement for the Revolving Credit Facility contains restrictive covenants substantially similar to those for the Senior Notes. The Revolving Credit Facility also includes certain additional covenants and restrictions relating to the activities of the Company which are customary for similar credit facilities and are not expected to have a material adverse effect on the conduct of the Company's business.
The Indentures relating to the Senior Notes and the Senior Subordinated Notes contain certain covenants, including, with limitation, covenants with respect to the following matters: (i) limitation on indebtedness; (ii) limitation on restricted payments; (iii) limitation on issuances and sales of restricted subsidiary stock; (iv) limitation on sale/leaseback transactions; (v) limitation on transactions with affiliates; (vi) limitation on liens; (vii) disposition of proceeds of asset sales; (viii) limitation on dividends and other payment restrictions affecting subsidiaries; and (ix) limitation of mergers, consolidations and transfers of assets. In addition, the Indenture related to the Senior Notes includes a covenant with respect to maintenance of adjusted consolidated net tangible assets, as defined.
Aggregate minimum principal payments for debt and the capital lease at December 31, 1996, for the next five years are as follows:
1997 $127,154 1998 - 1999 - 2000 - 2001 - -------- $127,154 ========
On June 11, 1994, LLC entered into two loan agreements with Joint Energy Development Investments Limited Partnership ("JEDI"), a venture between California Public Employees Retirement System and Enron Capital Corp. The first was a $20 million term loan, bearing interest at 12.5% payable monthly, maturing on June 11, 1997. The second loan, the development loan, provided for draws up to a maximum of $40 million, bearing interest at 15% payable monthly. In connection with this loan, LLC conveyed to JEDI a 20% overriding royalty interest (defined to be net of production costs) on certain unevaluated interests (computed prior to the one-eighth override conveyed to a related party discussed in Note 3) which commenced upon payment in full of the development loan. This interest was purchased from JEDI in December 1994, for $4.25 million. Proceeds from the Initial Offerings were used to repay these loans in December 1994.
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
10. EMPLOYEE BENEFIT PLANS
The Company has a 401(K) plan which covers all employees. The Company's contributions to the plan during 1996, 1995 and 1994 were $521,619, $513,690 and $432,202, respectively.
Stock-Based Compensation Plans
In October 1995, the FASB issued Statement of Financial Accounting Standards No. 123 ("SFAS 123"), "Accounting for Stock-Based Compensation," effective for the Company for 1996. Under SFAS 123, companies can either record expense based on the fair value of stock-based compensation upon issuance or elect to remain under the current "APB Opinion No. 25" method whereby no compensation cost is recognized upon grant if certain requirements are met. The Company is continuing to account for its stock-based compensation plans under APB Opinion No. 25. However, proforma disclosures as if the Company adopted the cost recognition requirements under SFAS 123 are presented below.
Had compensation for the Company's 1996 and 1995 grants for stock-based compensation plans been determined consistent with SFAS 123, the Company's net income and earnings per common share for the years ended December 31, 1996 and 1995 would have approximated the proforma amounts below:
The effects of applying SFAS 123 in this proforma disclosure are not indicative of future amounts. SFAS 123 does not apply to grants prior to 1995, and additional awards in the future are anticipated.
Prior to consummation of the Initial Offerings, the Board of Directors adopted and the stockholders approved a long-term incentive plan. The plan provides for not more than 1,500,000 shares of common stock to be issued to employees and directors of the Company. In 1995, the Board of Directors also adopted and the stockholders approved a long-term incentive plan for non- executive employees. This plan has an evergreen provision which replenishes options available for grant to 300,000 on January 1 of each year. In 1996, pending approval of the stockholders at the Annual Meeting, the Board of Directors adopted a plan which provides for not more than 1,000,000 shares of common stock to be issued to employees of the Company. Upon consummation of the Initial Offerings, the Company issued 645,000 stock options with an exercise price of $10.00 per share, the fair value at the date of grant. The options vest equally over a three-year period and terminate ten years from date of grant. A summary of the Company's stock options under both plans as of December 31, 1996 and 1995 and changes during the years ended on those dates is presented below:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The fair value of each option granted during the periods presented is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions: (i) dividend yield of 0%, (ii) expected volatility of 41.16% and 35.07% in the years 1996 and 1995, respectively, (iii) risk-free interest rate of 6.21% and 5.58% in the years 1996 and 1995, respectively, and (iv) expected life of 5 years.
The following table summarizes information about stock options outstanding at December 31, 1996:
In addition, in 1995, the Company issued 4,125 shares of stock which are considered bonus shares.
The Company is self-insured for employee medical benefits up to certain stop-loss limits.
The Company has no other significant formal benefit plans.
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
11. MAJOR CUSTOMERS
The Company sold the majority of its oil and gas to a few customers based on long-term contracts in 1996 and prior years. Sales to the following customers exceeded 10% of revenues during the years indicated (expressed in thousands):
12. COMMITMENTS AND CONTINGENCIES
While the Company is a defendant in various lawsuits in the ordinary course of business, management believes the potential liability in such lawsuits is not material. The Company maintains liability and other insurance customary in its industry. The Company is also subject to contingencies as a result of environmental laws and regulations. The related future cost is indeterminable due to such factors as the unknown timing and extent of the corrective actions that may be required and the application of joint and several liability. However, the Company believes that such costs will not have a material adverse effect on its operations or financial position.
The Company, as operator, is responsible for payment of plugging and abandonment costs on its properties. As of December 31, 1996, the total estimate of these costs on the Company's oil and gas properties was approximately $84.0 million, estimated to be incurred through the year 2011. The provision for such costs is recorded through depreciation, depletion and amortization expense. The estimates of plugging and abandonment costs and their timing may change due to many factors including, among others, actual production results, inflation rates, and changes in environmental laws and regulations.
In August 1993, the Minerals Management Service ("MMS") provided notice to lessees of Outer Continental Shelf ("OCS") leases that new levels of lease and area wide bonds would be required effective November 26, 1993, in connection with the plugging and abandoning of wells located offshore and the removal of all production facilities. The coverage is designed to reflect an appropriate balance between encouraging the maximum economic recovery of oil and natural gas from federal offshore leases while providing the federal government an adequate level of protection in the event the lessee defaults on its obligations to properly abandon lease wells and remove platforms and other structures from the property.
The MMS requires lessees of OCS properties to post bonds in connection with the plugging and abandonment of wells located offshore and the removal of all production facilities. Operators in the OCS waters of the Gulf of Mexico are currently required to post area wide bonds of $3 million or $500,000 per producing lease and supplemental bonds at the discretion of the MMS. On January 17, 1995, the Company entered into an agreement with Planet Indemnity Company ("Planet") whereby Planet agreed to issue $11.7 million of MMS surety bonds for the Company and the Company agreed to post collateral for same in favor of Planet. The collateral includes a mortgage on the Company's federal OCS leases in the amount of $8.2 million, a letter of credit for $2.0 million and a pledge of certain rights to escrowed funds. The Company has posted with the MMS an area wide bond of $3.0 million and supplemental bonds totaling $17.1 million. Pursuant to a schedule previously imposed by the MMS, the Company will be required to post additional supplemental bonds up to a level of $24.6 million by January 1999, unless the Company is determined by the MMS to be exempt from such requirement due to certain financial tests. In addition, the Company is currently working with the MMS to determine the level of supplemental bonding (and the timing thereof) which will be required for some of the recently acquired Central Gulf Properties. The Company does not anticipate that the cost of any such bonding requirements will materially affect the Company's financial position. Under certain circumstances, the MMS may require any Company operations on federal leases to be suspended or terminated. Any such suspensions or terminations could
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
have a material adverse effect on the Company's financial condition and operations. The MMS also intends to adopt financial responsibility regulations under the Oil Pollution Act of 1990 (the "OPA"). The OPA regulations impose a variety of regulations on "responsible parties" related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. A "responsible party" includes the owner or operator of a facility or vessel, or the lessee or permittee of an area in which an offshore facility is located. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by the OPA.
The OPA also imposes ongoing requirements on a responsible party, including proof of financial responsibility to cover at least some costs in a potential spill. As amended by the Coast Guard Authorization Act of 1996, OPA requires responsible parties for offshore facilities to provide financial assurance in the amount of $35 million to cover potential OPA liabilities. This amount is subject to upward regulatory adjustment up to $150 million.
In 1996, Statement of Position 96-1 ("SOP 96-1") - Environmental Remediation Liabilities was issued. The Company is required to adopt SOP 96-1 in 1997. The Company believes adoption of SOP 96-1 will not have a material effect on its results of operations or financial position.
Total rental expenses under operating leases amounted to approximately $690,000, $527,000 and $297,000 in 1996, 1995 and 1994, respectively.
In connection with the Initial Offerings, the Company entered into a Registration Rights Agreement (the "Registration Agreement") entitling Enron to require the Company to register common stock of the Company owned by Enron with the Securities and Exchange Commission (the "SEC") for sale to the public in a public offering, at no cost to Enron except for discounts and commissions, if any. During 1996, the unregistered shares subject to the Registration Agreement were transferred by Enron to Merrill Lynch Capital Markets, plc., together with Enron's rights under the Registration Agreement.
13. HEDGING ACTIVITIES
The Company hedges certain of its production through master swap agreements ("Swap Agreements"). The Swap Agreements provide for separate contracts tied to the NYMEX light sweet crude oil and natural gas futures contracts. The Company has contracts which contain specific contracted prices ("Swaps") that are settled monthly based on the differences between the contract prices and the average NYMEX prices for each month applied to the related contract volumes. To the extent the average NYMEX price exceeds the contract price, the Company pays the spread, and to the extent the contract price exceeds the average NYMEX price the Company receives the spread. In addition, the Company has combined contracts which have agreed upon price floors and ceilings ("Costless Collars"). To the extent the average NYMEX price exceeds the contract ceiling, the Company pays the spread between the ceiling and the average NYMEX price applied to the related contract volumes. To the extent the contract floor exceeds the average NYMEX price, the Company receives the spread between the contract floor and the average NYMEX price applied to the related contract volumes. Under the terms of the Swap Agreements, each counterparty has extended the Company a $5 million line of credit for use in conjunction with its hedging activities. As of February 24, 1997, the fair market value of all contracts covered by the Swap Agreements was approximately $0.6 million.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
As of December 31, 1996, after giving effect to three additional oil Swaps that the Company entered into in February 1997, the Company's open forward position on its outstanding crude oil Swaps was as follows:
The Company currently has no outstanding natural gas Swaps.
As of December 31, 1996, after giving effect to three additional Costless Collars entered into through February 24, 1997, the Company's open forward position on its outstanding Costless Collars was as follows:
Revenue was increased (decreased) under the Swap Agreements by approximately $(18.7) million, $(0.5) million and $1.7 million, respectively, for the years ended December 31, 1996, 1995 and 1994.
14. FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair value as of December 31, 1996 and 1995, of financial instruments other than current assets and liabilities is presented in the following table:
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
15. OIL AND GAS RESERVE INFORMATION - UNAUDITED
The Company's net proved oil and gas reserves at December 31, 1996, 1995 and 1994, have been determined by independent petroleum consultants in accordance with guidelines established by the SEC and the Financial Accounting Standards Board. Accordingly, the following reserve estimates are based upon existing economic and operating conditions at the respective dates. Future cash flows from oil and natural gas reserves were computed on the basis of prices being received at year end for oil and natural gas, adjusted for hedges in place at that date and the Company's policy regarding fuel gas.
There are many uncertainties inherent in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve data represent estimates only and should not be construed as being exact. In addition, the present values should not be construed as the current market value of the Company's oil and gas properties or the cost that would be incurred to obtain equivalent reserves.
The following tables set forth an analysis of the Company's estimated quantities of net proved and proved developed oil (includes condensate) and gas, all located offshore in the continental United States:
(1) The Company includes as proven reserves, future gas production estimated by Netherland, Sewell & Associates, Inc., to be used as fuel gas.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The following table presents the standardized measure of future net cash flows related to proved oil and gas reserves together with changes therein, as defined by the Financial Accounting Standards Board. The oil, condensate and gas price structure utilized to project future net cash flows reflects current prices at each year end and have been escalated only where known and determinable price changes are provided by contracts and law. Crude prices have declined significantly from December 31, 1996. Accordingly, the discounted future net cash flows would be reduced if the standardized measure was calculated at the latter date. Future production and development costs are based on current costs with no escalations. Estimated future cash flows have been discounted to their present values based on a 10% annual discount rate.
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
16. QUARTERLY FINANCIAL DATA- UNAUDITED
Summarized unaudited quarterly financial data for 1996 and 1995 are as follows:
17. EVENTS SUBSEQUENT TO DATE OF AUDITOR'S REPORT - UNAUDITED
On March 7, 1997, the Company completed an acquisition of certain interests in various state leases in the Main Pass 69 field, offshore Plaquemines Parish, Louisiana, from Chevron U.S.A. Inc. for a gross purchase price of $55.7 million. The acquisition includes interests in 27 producing wells located on 5,898 gross acres. Post acquisition, the Company owns a 100% working interest in the 27 wells. Current estimated production from the newly acquired interest is approximately 3,000 BOE per day net to the Company. The Company's ownership now encompasses a total of approximately 22,000 gross acres in the Main Pass 69 field.
ITEM 9:
ITEM 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item is partially included under Item 4A of this Form 10-K with the remainder of the required information incorporated by reference from the sections entitled "Management" and "Section 16(a) Beneficial Ownership Reporting Compliance" in the Company's definitive Proxy Statement for its 1997 Annual Meeting of Stockholders (the "Proxy Statement") to be filed with the Securities and Exchange Commission no later than April 30, 1997.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is incorporated by reference from the section entitled "Executive Compensation" in the Proxy Statement. Nothing in this report shall be construed to incorporate by reference the Board Compensation Committee Report on Executive Compensation or the Performance Graph which are contained in the Proxy Statement, but expressly not incorporated herein.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item is incorporated by reference from the section entitled "Security Ownership of Certain Beneficial Owners and Management" in the Proxy Statement.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is incorporated by reference from the section entitled "Certain Relationships and Other Transactions" in the Proxy Statement.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a) Financial Statements and Supplementary Data, Financial Statement Schedules and Exhibits
2. Consolidated Financial Statement Schedules
All consolidated financial statement schedules have been omitted because they are not required, are not applicable or the information required has been included elsewhere herein.
3. Exhibits and Financial Statement Schedules (except as otherwise designated below, all exhibits have been previously filed.)
a. Exhibits
3.1 Certificate of Incorporation of the Company (filed as Exhibit 3.1 to the Company's Registration Statement on Form S-1 (33-84308) and incorporated herein by reference)
3.2 Bylaws of the Company (filed as Exhibit 3.3 to the Company's Registration Statement on Form S-1 (33-84308) and incorporated herein by reference)
4.1 Indenture among the Company, FRI Louisiana and Shawmut Bank Connecticut, National Association, as Trustee, relating to the 13 1/2% Senior Notes due 2004 (filed as Exhibit 4.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994 and incorporation herein by reference)
4.2 First Supplemental Indenture, dated as of September 19, 1996, among the Company, the Subsidiary Guarantors named therein, and Fleet National Bank (formerly Shawmut Bank Connecticut, National Association), as Trustee (filed as Exhibit 4.1 to the Company's Current Report on Form 8-K dated September 26, 1996, and incorporated herein by reference)
4.3 Indenture among the Company, the Subsidiary Guarantors named therein and Fleet National Bank, as Trustee relating to the 9 3/4% Senior Subordinated Notes due 2006 (filed as Exhibit 4.1 to the Company's Quarterly Report Form 10-Q for the quarter ended September 30, 1996 and incorporated herein by reference).
*10.1 1994 Long-Term Incentive Plan (filed as Exhibit 10.3 to the Company's Registration Statement on Form S-1 (33-84308) and incorporated herein by reference)
*10.2 Form of Indemnification Agreement among the Company and certain executive officers (filed as Exhibit 10.5 to the Company's Registration Statement on Form S-1 (33-84308) and incorporated herein by reference)
10.3 Credit Agreement among FRI Louisiana and certain lenders in the amount of $50,000,000, as amended (filed as Exhibit 10.3 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994 and incorporated herein by reference)
10.3.1 Amendment to Credit Agreement dated December 20, 1995
10.3.2 Second Amendment to Credit agreement, dated August 14, 1996 (filed as Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1996 and incorporated herein by reference)
10.4 Mortgage, Assignment of Production, Security Agreement and Financing Statement (filed as Exhibit 10.4 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994 and incorporation herein by reference)
*10.5 Assignment and Bill of Sale between FRI Louisiana (as assignor), Franks Petroleum, Inc. (as assignee), and Sable Minerals, Inc. dated May 22, 1992, as amended by that Act of Correction dated December 14, 1992 (filed as Exhibit 10.25 to the Company's Registration Statement on Form S-1 (33-84308) and incorporated herein by reference)
*10.6 Assignment and Bill of Sale between FRI Louisiana (as assignor), Franks Petroleum, Inc. (as assignee), and Sable Minerals, Inc. dated June 9, 1993 (state leases, private leases and BLM lease) (filed as Exhibit 10.26 to the Company's Registration Statement on Form S-1 (33-84308) and incorporated herein by reference)
*10.7 Assignment of Record Title Interest in a Lease for Oil and Gas or Geothermal Resources between FRI Louisiana (as assignor), and Franks Petroleum, Inc. and Sable Minerals, Inc. (as assignees) dated May 12, 1993 (BLM Form) (filed as Exhibit 10.27 to the Company's Registration Statement on Form S-1 (33-84308) and incorporated herein by reference)
*10.8 Overriding Royalty Assignment and Bill of Sale between FRI Louisiana (as assignor) and Sable Minerals, Inc. (as assignee) dated June 9, 1993 (OCS leases) (filed as Exhibit 10.28 to the Company's Registration Statement on Form S-1 (33-84308) and incorporated herein by reference)
10.9 Pledge of Production Proceeds and Trust Agreement dated May 12, 1992, by and among Shell Offshore, Inc., FRI Louisiana and First National Bank of Commerce, New Orleans, Louisiana (filed as Exhibit 10.31 to the Company's Registration Statement on Form S-1 (33-84308) and incorporated herein by reference)
10.10 Pledge of Production Proceeds and Trust Agreement dated May 12, 1993, by and among Shell Offshore, Inc., FRI Louisiana and First National Bank of Commerce, New Orleans, Louisiana (filed as Exhibit 10.32 to the Company's Registration Statement on Form S-1 (33-84308) and incorporated herein by reference)
10.11 Registration Rights Agreement of Enron Finance Corp. (filed as Exhibit 10.14 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994 and incorporation herein by reference)
+10.12 Waiver and Amendment of Registration Rights Agreement, effective as of December 7, 1994
+10.13 Second Amendment to Registration Rights Agreement, dated August, 1996, among the Company, FRI Louisiana, Enron Finance Corp. and Merrill Lynch Capital Markets plc
10.14 Indenture Assumption Agreement by FRI Louisiana in favor of the Company (Senior Notes) (filed as Exhibit 10.15 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994 and incorporation herein by reference)
+10.15 Indenture Assumption Agreement by FRI Louisiana in favor of the Company (Senior Subordinated Notes)
10.16 Crude Oil Purchase Contract, dated May 12, 1993, between FRI Louisiana and Shell Oil Company, as amended (filed as Exhibit 10.16 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994 and incorporation herein by reference)
10.17 MMS Bonding Agreement, dated January 17, 1995, between FRI Louisiana and Planet Indemnity Company, with related Act of Mortgage and Financing Statement (filed as Exhibit 10.17 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994 and incorporation herein by reference)
10.18 Modification Agreement effective May 1, 1996 to that MMS Bonding Agreement, dated January 17, 1995, between FRI Louisiana and Planet Indemnity Company (filed as Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996 and incorporated herein by reference)
10.19 Gas Purchase Agreement, dated January 1, 1995, between FRI Louisiana and Enron Capital & Trade Resources Corp. (filed as Exhibit 10.18 to the Company's Annual Report on Form 10-K for the year ended December 31, 1994 and incorporation herein by reference)
*10.20 Form of Employment Agreement entered into between the Company and Robert L. Belk, Robert K. Reeves, David J. Morgan and Richard G. Zepernick, Jr., effective as of September 1, 1995 (filed as Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1995 and incorporated herein by reference)
*10.21 Form of First Amendment to Employment Agreements dated May 8, 1996 and effective as of September 1, 1995 (filed as Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1996 and incorporated herein by reference)
+*10.22 Form of Second Amendment to Employment Agreements dated December 6, 1996 21.1 Subsidiaries of Registrant (filed as Exhibit 21.1 to the Company's Annual Report on Form 10-K for the year ended December 31, 1995 and incorporated herein by reference) +23.1 Consent of Arthur Andersen, LLP +23.2 Consent of Netherland, Sewell & Associates, Inc. +27.1 Financial Data Schedule
*Management contract or compensatory plan. +Filed herewith.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
FLORES & RUCKS, INC.
By: /s/ James C. Flores ------------------- James C. Flores Chairman of the Board and Chief Executive Officer
Date: March 27, 1997
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the dates indicated.