ITEM 1. BUSINESS.
HISTORY AND OVERVIEW
Basin Exploration, Inc. ("Basin" or the "Company") is a Denver- based independent oil and gas company engaged in exploration, acquisition, development, and production operations in the United States, including the Gulf of Mexico.
The Company was formed in 1981 to participate in an emerging exploitation play in the Denver-Julesburg ("D-J") Basin, primarily through management of small drilling programs. Growth accelerated in 1988 when the Company initiated a series of acquisitions of D-J Basin properties, followed by subsequent exploitation and development. After an initial public offering of common stock in May 1992, the Company embarked on an aggressive development program for its D-J Basin assets, and also expanded its activities to include acquisition and development of proved properties and exploration for new reserves in other areas within the Rocky Mountain region.
From 1988 through 1994, the Company completed acquisitions for a total cost of $84 million and incurred related development costs totaling $99 million. As a result of these activities, Basin increased its estimated proved reserves 12-fold, from 20 Bcfe at October 31, 1989 to 247 Bcfe at December 31, 1994. Due, in part, to capital constraints, low gas prices in the Rocky Mountain region, and a reduced inventory of economically viable exploitation projects, total capital expenditures related to oil and gas properties declined from $67 million in 1994 to $16 million in 1995. This reduced level of investment, plus the effects of lower gas prices and dispositions of low-margin properties, resulted in a decline in proved reserves at December 31, 1995 to 207 Bcfe.
In late 1995, the Company responded to the reduction in its inventory of exploitation projects, and to its assessment of the relative attractiveness of alternative investment opportunities, by determining to implement a strategic redirection incorporating the following plans: (1) to improve its liquidity by monetizing assets; (2) to focus its exploration efforts in the Gulf of Mexico rather than in the Rocky Mountains; (3) to aggressively pursue acquisition opportunities over a broader geographic area and in coordination with the Company's exploration activities; and (4) to hire personnel for management and technical positions who have had direct experience and favorable track records conducting these planned operations. Actions subsequently taken, and certain related consequences, include the following:
- In two transactions closed in March 1996 and June 1996, respectively, the Company sold all of its assets in the D-J Basin for $123.5 million. These assets represented approximately two-thirds of the Company's wells and 70% of its proved oil and gas reserves at December 31, 1995. These transactions enabled the Company to eliminate all of its long-term debt utilizing a portion of the sales proceeds and created significant liquidity and financial flexibility for pursuit of new capital projects. However, as the Company disposed of a substantial portion of its operating assets, it has initially experienced significant reductions in oil and gas reserves, production and cash flow. Pro forma the disposition of its D-J Basin assets as of December 31, 1995, the Company's proved oil and gas reserves at that date totaled approximately 63 bcfe.
- During the fourth quarter of 1995, the Company discontinued Rocky Mountain prospect generation and established an office in Houston, Texas to focus initially on exploration in the shallow waters of the Gulf of Mexico offshore Louisiana and Texas. The Houston office currently has a staff of nine, including senior geoscientists and petroleum engineers, each of whom has extensive experience operating in this area. The Company is aggressively utilizing advanced technologies in its exploration effort, such as three-dimensional ("3-D") geophysics and computer-aided exploration ("CAEX"), and has acquired state-of-the-art workstations and access to large 3-D seismic data bases. In its first year of operations, the Company made significant progress in building its 3-D seismic data base and its inventory of prospect leaseholds, and also drilled four exploratory wells, two of which were successful. The Company's initial Gulf Coast production is expected to occur during 1997.
- The Company added senior level acquisitions personnel in late 1995 and early 1996 to strengthen its ability to evaluate and pursue proved oil and gas properties with enhancement potential. During September 1996, the Company acquired a 25% interest in the Jepson-Holler Draw secondary oil recovery unit in Wyoming, in exchange for $1 million and the Company's interests in 18 producing wells. The Company invested an additional $2.9 million on the development of this property in 1996. In February 1997, the Company acquired interests in three lease blocks in the Gulf of Mexico with proved, nonproducing reserves for $14.4 million. See "Present Activities."
- In conjunction with these changes in strategy and operations, five of six vice presidents with the Company at the beginning of 1995 left the Company and five individuals joined Basin as vice presidents during the period from August 1995 through March 1996. These new vice presidents include executive officers who assumed leadership roles in the areas of exploration, acquisitions, project development, and finance.
These developments have resulted in the Company being considerably smaller, as measured by assets, revenues, or employees, than at the beginning of 1996, but with substantially enhanced liquidity and capability to pursue new capital projects. The Company's divestment of its D-J Basin assets and its commitment to Gulf of Mexico exploration have also significantly changed the character and risk profile of its oil and gas capital expenditure activities. See "Management's Discussion and Analysis of Financial Condition and Results Of Operations."
The Company's proved oil and gas reserves at December 31, 1996 totaled approximately 77 Bcfe and were located primarily in the Powder and Green River basins in Wyoming and in the shallow waters of the Gulf of Mexico offshore Louisiana.
BUSINESS STRATEGY
Basin's business objective is to increase shareholder value through profitable expansion, development, and production of oil and gas reserves. To achieve its objective, the Company intends to:
. retain experienced technical staff with successful track records;
. pursue a diversified mix of exploration and acquisition activities;
. utilize state-of-the-art technologies, such as CAEX and 3-D seismic;
. focus operations geographically to leverage regional knowledge and develop competitive advantages;
. frequently rationalize assets to achieve efficiencies and improve operating margins; and
. maintain strong financial condition.
EXPLORATION
Exploration activities have been increasing since 1994 and are expected to be integral to the Company's future growth. Prior to 1996, exploration activities were conducted exclusively in the Rocky Mountain region. However, in 1996 the Company began to focus its exploration activities in the shallow waters of the Gulf of Mexico, off the coasts of Louisiana and Texas. This change in strategy reflects a number of considerations, including the following:
- The Gulf of Mexico is a prolific oil and gas province and the Company believes that significant potential remains for discovery of new reserves.
- State-of-the-art technologies, such as CAEX and 3-D seismic, have been more successfully employed in the Gulf of Mexico than in most other regions of the U.S. to improve drilling success rates and enhance economic returns.
- The extensive amount of seismic and other geologic data covering the area is readily available at reasonable cost.
- Open access to government-owned mineral rights reduces barriers to entry.
- This area has a well-developed infrastructure, including oil and gas transportation systems and service providers, facilitating cost-effective operations and favorable product prices.
- Typically, operations in this area are characterized by a favorable ratio of low-risk development capital to high-risk test capital.
This operating area is highly competitive and the Company believes that a key to its success will be attraction and retention of geoscientists and other professional staff with extensive experience operating in the area. Accordingly, the Company opened a regional office in Houston, Texas in December 1995. This office currently has a staff of nine, including senior geoscientists and petroleum engineers, all of whom are experienced in Gulf Coast operations. In addition, certain
members of the Company's senior management based in Denver have had considerable experience in providing support for operations in the Gulf Coast area, both onshore and offshore.
The Company generates prospect leads through utilization of regional 2-D and 3-D seismic data bases, integrating regional geology. The Company bids for leaseholds at federal and state Gulf of Mexico lease sales and also pursues joint venture and farm-in opportunities for blocks under existing lease. Generally, the Company intends to target prospects with at least 20 Bcfe of estimated reserves potential, in water depths of less than 300 feet. Basin will seek to operate whenever possible, in order to maintain maximum control of capital and operating costs, and of timing of prospect development. The Company will typically seek to retain between one-quarter and two- thirds of each prospect. The Company also intends to pursue acquisitions of producing properties in the region where there is identified exploration or development potential. Such acquisitions, with production facilities and equipment already in place, can create the opportunity for economic development of reserve accumulations that might otherwise be too small.
In its first year of Gulf Coast operations, the Company participated in drilling four exploratory wells, two of which were successful. The Company also accumulated an inventory of prospect acreage. At December 31, 1996, the Company held leaseholds relating to 33,340 gross (28,128 net) undeveloped acres in the Gulf of Mexico, mostly offshore Louisiana. See "Properties" for additional information regarding offshore acreage holdings, including "Present Activities" for information relating to events in 1997.
Since nine or more months are typically required for platform fabrication and installation for a new discovery (unless such infrastructure is already in place), the Company is not anticipating any significant 1997 contributions of production or cash flow resulting from current year Gulf Coast exploration. The company does expect production during part of 1997 from three of its Gulf of Mexico properties that are presently attributed proved reserves. See "Management's Discussion and Analysis of Financial Condition and Results Of Operations - Liquidity and Capital Resources."
ACQUISITIONS
Prior to 1996, the Company's growth was achieved primarily through acquisition of properties with proved and probable reserves, and subsequent exploitation and development. The Company initially executed a series of acquisitions in the D-J Basin, ultimately creating a substantial base of operations that facilitated development of in-depth knowledge of the area, including its geologic and reservoir characteristics, and also enabled the achievement of certain operating and administrative efficiencies. Later, the Company executed two acquisitions of Powder River Basin properties in Wyoming to establish another base of operations where similar operating advantages could be achieved.
In 1996, Basin added senior level acquisitions personnel to enhance the Company's ability to source, evaluate and capture acquisition opportunities in a broader geographic area. The Company intends to opportunistically pursue property acquisitions with upside potential in its current operating areas and potentially in other major producing domestic basins. Basin intends to utilize advanced technologies, including 2-D and 3-D seismic data and CAEX where applicable, to identify properties with upside potential that might be acquired. The Company's petroleum engineers will work in conjunction with the Company's in-house geoscientists or outside consultants, depending on the area, to effectively integrate such data in evaluations. As part of its integrated exploration and acquisition strategies, Basin will particularly seek to make acquisitions of producing properties in the Gulf Coast area where exploration potential has been identified. Once properties are discovered or acquired in an area, it is likely that the Company will attempt to acquire additional properties in the region to achieve operating advantages.
The Company will generally focus on acquisition opportunities where it believes it can enhance the value of properties through one or more of the following means:
. Exploratory drilling
. Development drilling
. Recompletions
. Reservoir stimulation
. Secondary or tertiary recovery operations
. Cost reductions
The Company's two most recent acquisitions are indicative of such properties with assessed upside potential. An interest in the Jepson- Holler Draw Unit in Wyoming was acquired in September 1996. This property was recently unitized for purposes of initiating secondary recovery operations through waterflooding, and water injection commenced in January 1997. In February 1997, the Company acquired interests in three Gulf of Mexico lease blocks with recently drilled wells awaiting further development. In addition to completion and tie-in of the three wells that have been drilled, the Company believes these properties hold potential upside that may be realizable through development drilling and further exploration. See "Properties."
Because of intense competition for proved property acquisitions and other factors, it is impossible to project the timing or dollar amount of acquisition activity.
MARKETING
The majority of the Company's gas and natural gas liquids from fields in the Rocky Mountain region are sold under marketing arrangements where prices received are responsive to changes in regional spot markets. These include short-term contracts under which gas is sold at the wellhead at market-sensitive prices, and long-term (often for the life of the lease) percentage-of-proceeds contracts with gas processors.
KN Gas Gathering ("KNGG") purchases virtually all of the Company's Powder River Basin gas and natural gas liquids from the Company's operated wells under a series of contracts with price realizations similar to other percentage-of-proceeds contracts in the area. These contracts generally do not have minimum take provisions and thus depend on KNGG's ability to find a market for the Company's gas and natural gas liquids. The Company is in the process of consolidating all its KNGG contracts into a single percentage-of- proceeds term contract. If KNGG were to cease purchasing the Company's gas, the Company believes that it could sell its gas and natural gas liquids to other purchasers and processors in the area, although such sales would require capital expenditures for gathering system modification and might not be on terms as favorable as those characterizing the KNGG sales. The Company does not believe that the loss of KNGG as a purchaser would have a material adverse effect on the Company.
Demand for natural gas is highly seasonal, with demand generally higher in the colder winter months and in hot summer months. As a result, the price received for spot market natural gas may vary significantly between seasonal periods. To date, the Company generally has been able to sell its available spot market natural gas at prevailing spot market prices, such that volumes sold have not materially fluctuated seasonally. There is no assurance, however, that the Company will be able to continue to achieve this result.
Oil from the Company's Rocky Mountain properties is generally sold under term contracts that yield a premium over local posted prices.
Because of the well-developed transportation infrastructure and the relatively large number of active oil and gas purchasers in the Gulf Coast area, including in the Gulf of Mexico where the Company is conducting exploration and acquisition activities, the Company does not anticipate that it will have difficulty in marketing its production in this region, when established, at prevailing spot market prices.
For much of the past decade, the markets for oil and natural gas have been volatile. The Company anticipates that such markets will continue to be volatile in the foreseeable future. Oil and gas price fluctuations have a significant impact on the Company's business since virtually all of the Company's operating revenues are ordinarily derived from sales of its oil and gas production. The Company believes that the loss of one or more of its current oil or natural gas spot purchasers would not have a material adverse effect on the Company's business because any individual purchaser should be readily replaceable by another purchaser who could be expected to pay approximately the same sales price.
Basin periodically enters into oil and gas price hedging agreements as conditions are deemed to warrant. Such transactions affecting the three year period ended December 31, 1996, or currently in effect with respect to subsequent periods, are described below under "Management's Discussion and Analysis of Financial Condition and Results Of Operations - Liquidity and Capital Resources" and in the Notes to Consolidated Financial Statements.
COMPETITION
Competition in the oil and gas industry is intense, particularly with respect to the acquisition of producing properties and proved undeveloped acreage and the acquisition of interests in offshore exploration prospects in the Gulf of Mexico. Major and independent oil and gas companies, as well as individuals and drilling programs, actively bid for desirable oil and
gas properties, as well as for the equipment and labor required to operate and develop such properties. A number of Basin's competitors have financial resources and exploration and development budgets that are substantially greater than those of Basin, which may adversely affect the Company's ability to successfully compete. In addition, many of the Company's larger competitors may be better able to respond to factors that affect the demand for oil and natural gas production such as changes in worldwide oil and natural gas prices and levels of production, the cost and availability of alternative fuels, and the application of government regulations. The Company commenced operations in the Gulf of Mexico area during 1996, where it had not previously been active. Competition from major and large independent oil and gas companies is significantly greater in this area than in the Rocky Mountain region, where the Company had conducted all of its previous operations.
REGULATION
The following discussion of regulation of the oil and gas industry is necessarily brief and is not intended to constitute a complete discussion of the various statutes, rules, regulations or governmental orders to which operations of Basin may be subject.
Price Controls on Liquid Hydrocarbons.
There are currently no federal price controls on liquid hydrocarbons (including oil and natural gas liquids). As a result, Basin sells oil produced from its properties at unregulated market prices.
Federal Regulation of Sales and Transportation of Natural Gas.
Historically, the transportation and sale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act ("NGA"), the Natural Gas Policy Act of 1978 ("NGPA") and regulations promulgated thereunder. The Natural Gas Wellhead Decontrol Act of 1989 eliminated all regulation of wellhead gas sales effective January 1, 1993. As a result, Basin's gas sales are no longer regulated.
The transportation and resale in interstate commerce of natural gas produced and sold by Basin continues to be subject to regulation by the Federal Energy Regulatory Commission ("FERC") under the NGA. The transportation and resale of natural gas transported and resold within the state of its production is usually regulated by the state involved. Although federal and state regulation of the transportation and resale of natural gas produced by Basin currently does not have any material direct impact on Basin, such regulation does have a material impact on the market for Basin's natural gas production and the price Basin receives for its natural gas production. Adverse changes in the regulation affecting Basin's gas markets could have a material impact on Basin.
Commencing in the mid-1980s and continuing until the present, the FERC promulgated several orders designed to correct market distortions and to make gas markets more flexible and competitive. These orders have had a profound influence on natural gas markets in the United States and have, among other things, increased the importance of interstate gas transportation and encouraged development of a large spot market for gas.
On April 8, 1992, the FERC issued Order No. 636 requiring material restructuring of the sales and transportation services provided by interstate pipeline companies. The primary element of Order No. 636 was the mandatory unbundling of interstate gas transportation from gas sales by the pipelines. All interstate pipelines were required to offer transportation services and storage separately from their gas sales on a nondiscriminatory basis. Most pipelines have moved all or almost all of their business of buying and selling gas to affiliated marketing companies.
The transition to unbundled open access transportation occurred without major apparent market disruption. The current gas market is characterized by a large number of gas buyers and sellers and there appears to have developed a substantial increase in the flexibility of the natural gas industry and its capacity to respond to changing needs and conditions.
Although Order No. 636 does not regulate gas producers such as Basin, Order No. 636 appears to have achieved the FERC's stated goal of fostering increased competition within all phases of the natural gas industry. It is unclear what impact, if any, that increased competition will have on Basin as a gas producer and seller.
The Outer Continental Shelf Lands Act (the "OCSLA") requires that all pipelines operating on or across the Outer Continental Shelf (the "OCS") provide open-access, non-discriminatory service. Pursuant to a February 1996 Policy Statement by the FERC in Docket No. RM96-5-000, only certain "feeder lines" as defined in Section 5(f)(2) of the OCSLA are exempt from the FERC's authority to impose these competitive requirements. In addition, under Section 1 of the NGA, the FERC has regulatory jurisdiction over the transportation and sale of natural gas in interstate commerce, but it does not
have authority over the "production or gathering" of natural gas.
In a February 1996 decision in Docket No. RM96-5-000, the FERC issued a re-evaluation of its test for establishing whether a pipeline is or is not engaged in the "gathering" of natural gas. The FERC decided to retain the "primary function test" as articulated in its decision in Amerada Hess, 52 FERC 61,268 (1990), with one ------------ modification, which is that, in applying the "primary function test" to offshore facilities, the FERC will presume that facilities located in deep water are primarily engaged in gathering or production in recognition of the technology and topography particular to operations in deep waters. Although the Company expects to own and operate gathering lines upon the successful development of its offshore exploration prospects, it is unknown what impact this decision will have on Company operations on the OCS or the Company's production from the OCS, as implementation of the "primary function test" is generally made on a case-by-case basis. If the FERC were to redefine its jurisdiction over gathering lines more expansively, there could be a reduction in available pipeline space for existing shippers in the Gulf of Mexico that own and operate gathering lines. On the other hand, if the FERC were to determine that it was no longer necessary to regulate the rates and service of OCS transmission facilities under the NGA, the Company could experience an increase in transmission costs associated with its OCS natural gas production and, possibly, reduced access to OCS transmission capacity.
In addition to FERC regulation of interstate pipelines under the NGA, various state commissions also regulate the rates and services of pipelines whose operations are purely intrastate in nature. To the extent intrastate pipelines elect to transport gas in interstate commerce under certain provisions of the NGPA, those transactions are subject to limited FERC regulation under the NGPA.
There are many legislative proposals pending in Congress and in the legislatures of various states that, if enacted, might significantly affect the oil and gas industry. Basin is not able to predict what will be enacted and thus what effect, if any, such proposals would have on Basin.
State and Local Regulation of Drilling and Production.
State regulations govern operational matters such as permits and bonds for drilling, reclamation and plugging, spacing and pooling of wells, and reporting requirements. The states in which Basin operates or plans to operate also have a variety of statutes and regulations governing conservation matters, ranging from establishment of maximum rates of production from oil and gas wells to the proration of production to the market demand for oil and gas to the limitation on ceiling prices for gas sold within the state. In 1991, the State of Oklahoma enacted legislation restricting the output of certain high- volume gas wells in response to prevailing low gas prices and the States of Texas and Louisiana have considered similar regulatory initiatives. Any limitation substantially similar to that enacted by Oklahoma would not have a material impact on Basin's current level of production, whether for oil or gas, since Basin's wells do not produce at a level high enough to meet the threshold for restriction contained in the legislation. However, if similar legislation with lower thresholds were to be enacted in the states in which Basin operates, or if Basin acquires or develops properties in state waters in the Gulf of Mexico or onshore in states such as Texas or Oklahoma having higher levels of production than the historic levels of Basin's Rocky Mountain properties, Basin's ability to market its production could be affected.
Also in recent years, pressure has increased in states in which the Company has been active (especially Colorado) to mandate compensation to surface owners for the effects of oil and gas operations and to increase regulation of the oil and gas industry at the local government level. Such local regulation in general is aimed at increasing the involvement of local governments in the permitting of oil and gas operations, requiring additional restrictions or conditions on the conduct of operations to reduce the impact on the surrounding community and increasing financial assurance requirements. Accordingly, such regulation has the potential to delay and increase the cost, or even in some cases to prohibit entirely, the conduct of the Company's drilling activities.
Environmental Matters.
The production, handling, transportation and disposal of oil and gas and by-products are subject to regulation under federal, state and local environmental laws. In most instances, the applicable regulatory requirements relate to water and air pollution control and solid waste management measures or to restrictions on operations in environmentally sensitive areas such as wetlands or wilderness. In connection with its acquisitions, Basin performs environmental assessments. To the extent environmental liabilities have been identified, such liabilities are not material or the Company has negotiated agreements requiring the sellers of the properties to undertake the required clean up. Basin has assumed responsibility for some of these matters identified. Environmental assessments have not been performed on all of Basin's properties. To date, expenditures for environmental control facilities and for remediation have not been significant in relation to the results of operations of Basin. Basin believes, however, that it is reasonably likely that the trend in environmental legislation and
regulations will continue toward stricter standards. For instance, efforts have been made in Congress to amend the Resource Conservation and Recovery Act to reclassify oil and gas production wastes as "hazardous waste," the effect of which would be to further regulate the handling, transportation and disposal of such waste. If such legislation were to pass, it could have a significant adverse impact on the operating costs of Basin, as well as the oil and gas industry in general.
The Oil Pollution Act of 1990 (the "OPA"), as amended in 1996, and regulations thereunder 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 the 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 in anticipation of an oil spill event. Specifically, the OPA requires a responsible party to maintain proof of $35,000,000 of financial responsibility for traditional offshore facilities. The President, however, may establish a higher degree of financial responsibility ($150,000,000) based on risk. Offshore facilities in state waters are held to a financial responsibility of $10,000,000 but facilities transporting, storing or otherwise handling up to 1,000 barrels of oil at any one time are exempt from these financial responsibilities. Financial responsibility can be established through insurance, guarantee, indemnity, surety bond, letter of credit, qualification as a self-insurer or a combination thereof. The 1996 amendments to the OPA eliminated third party suits against guarantors, except where a responsible party is bankrupt or where the claimant is a federal governmental agency, and a guarantor's total liability is limited to the amount of financial responsibility provided. While the OPA could impose substantial additional annual costs on the Company or otherwise materially adversely affect the Company, the impact of these rules should not be any more adverse to the Company than it will be to other similarly situated owners or operators in the Gulf of Mexico.
The OPA also imposes other requirements, such as the preparation of an oil spill contingency plan. Failure to comply with ongoing requirements or inadequate cooperation during a spill event may subject a responsible party to civil or criminal enforcement actions.
The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances. Under CERCLA such persons or companies would be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
New initiatives regulating the disposal of oil and gas waste are also pending or have been enacted in certain states, including states in which Basin conducts operations, and these various initiatives could have a similar impact on Basin. The Colorado Oil and Gas Conservation Commission, for example, has enacted rules regarding the disposal of oilfield waste, the closure and remediation of production pits and reclamation procedures. These rules establish significant permitting, record-keeping and compliance procedures that may require the termination of production from marginal wells for which the cost of compliance would exceed the value of remaining production and could lead to the incurring of significant remediation costs for properties found to have caused groundwater contamination or other environmental problems.
Federal Leases.
A significant percentage of the Company's operations is conducted on public lands, both in the Rocky Mountain region and in the Gulf of Mexico. Operations on onshore federal leases must be conducted in accordance with permits issued by the Bureau of Land Management and are subject to a number of other regulatory restrictions, such as winter game restrictions. Moreover, on certain federal leases, prior approval of drillsite locations must be obtained from the Environmental Protection Agency.
Offshore leases in the Gulf of Mexico, beyond the limits of state ownership, are administered by the United States Department of the Interior Minerals Management Service (the "MMS"). Such leases are issued through competitive bidding, contain relatively standardized terms and require compliance with detailed MMS regulations and orders pursuant to the OCSLA (which are subject to change by the MMS). For offshore operations, lessees must obtain MMS approval for
exploration plans and development and production plans prior to the commencement of such operations. In addition to permits required from other agencies (such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency), lessees must obtain a permit from the MMS prior to the commencement of drilling. The MMS has promulgated regulations requiring offshore production facilities located on the OCS to meet stringent engineering and construction specifications. The MMS also has regulations restricting the flaring or venting of natural gas. Similarly, the MMS has promulgated other regulations governing the plugging and abandonment of wells located offshore and the removal of all production facilities.
The United States Department of Transportation ("DOT"), through its Office of Pipeline Safety, also imposes certain requirements on parties responsible for pipeline platforms located on the OCS. In October 1995, the MMS indicated its intent to review all of its regulations governing offshore regulations after the MMS and DOT completed a new Memorandum of Understanding regarding the agencies' respective authority over offshore operations. To date, the pertinent regulations have not been implemented as the contemplated Memorandum of Understanding has just been finalized.
To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met. The cost of such bonds or other surety can be substantial and there is no assurance that bonds or other surety can be obtained in all cases. In December 1995, the MMS proposed changes to its bonding requirements that, if implemented as proposed, would (i) impose the duty on any lessee of an offshore lease to meet end-of-lease obligations if the designated operator is unable to do so, (ii) establish joint and several liability for plugging and abandonment of wells, removal of platforms and other facilities, and clearance of well and platform locations, among OCS lessees, assignees and assignors, thus creating residual liability in certain parties for these obligations, (iii) establish some form of assurance that holders of OCS leases establish a means of funding their end-of-lease obligations by allowing the MMS Regional Director to require additional security of lessees and (iv) increase the level of bond coverage for certain exploration activities drilling deep stratigraphic test wells and allow the MMS Regional Director to require, on a case-by-case basis, posting of additional bonds or other security in order to increase the amount of coverage under an existing bond. If implemented, these requirements could increase the Company's current bonding liabilities in a substantial way, and would also impact certain residual liabilities that the Company may have, both with respect to existing leases acquired from third parties and with respect to leases that it may dispose of in the future.
Under certain circumstances, the MMS may require any operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect the Company's financial condition and operations.
On January 24, 1997, the MMS published a notice of proposed rulemaking which, if adopted, would significantly change the current rules governing the value of crude oil for royalty payments on federal leases. The new valuation rule would retain the concept of gross proceeds for calculating royalties on production sold to third parties in arm's-length transactions, but only in certain narrow circumstances. As proposed, the majority of oil sold under arm's- length contracts as well as non-arm's-length contracts would be valued using an index pricing method as adjusted for location, quality, and transportation rather than the contract price. If adopted as proposed, the MMS' rule would have a substantial impact on the Company's royalty payments to the federal government and could in many cases require that it pay royalty on a value (index price) higher than that which it actually receives (contract price) for its oil. As of this date, the MMS has not finalized or adopted the proposed rule, and its impact, if any, on the Company is therefore uncertain.
TITLE TO PROPERTIES
As is customary in the oil and natural gas industry, the Company makes only a cursory review of title to farmout acreage and to onshore undeveloped oil and natural gas leases upon execution of the contracts. Prior to the commencement of drilling operations, a thorough title examination is conducted and curative work is performed with respect to significant defects. The Company performs complete reviews of title to federal and state offshore lease blocks prior to acquisition. To the extent title opinions or other investigations reflect material title defects, the seller of the property, rather than the Company, is typically responsible for curing any such title defects at its expense. If the Company were unable to remedy or cure any title defect of a nature such that it would not be prudent to commence drilling operations on undeveloped properties, the Company could suffer a loss of its entire investment in the property. The Company has obtained title opinions on substantially all of its producing properties and believes that it has satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. The Company's producing properties are mortgaged to its banks in connection with its revolving credit facility.
OPERATIONAL HAZARDS AND INSURANCE
The Company's operations are subject to the usual hazards incident to the drilling and production of oil and gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution, releases of toxic gas and other environmental hazards and risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. Offshore operations are subject to the additional hazards of marine operations, such as capsizing of vessels, collision and adverse weather and sea conditions.
The Company maintains insurance of various types to cover its operations. The Company has $1,000,000 of general liability insurance and an additional $30,000,000 of excess liability insurance. In addition, the Company maintains operator's extra expense coverage which applies to care, custody and control of wells drilled or completed. The Company's insurance does not cover every potential risk associated with the drilling and production of oil and gas. In particular, coverage is not obtainable for certain types of environmental hazards. The occurrence of a significant adverse event, the risks of which are not fully covered by insurance, could have a material adverse effect on the Company's financial condition and results of operations. Moreover, no assurance can be given that the Company will be able to maintain adequate insurance in the future at rates it considers reasonable.
EMPLOYEES
At December 31, 1996, Basin had 64 employees, including 19 employed in field operations and 45 employed in its Denver headquarters or Houston district office. None of Basin's employees are subject to a collective bargaining agreement and Basin considers its relations with its employees to be good.
ITEM 2.
ITEM 2. PROPERTIES.
Prior to 1996, the Company's oil and gas properties were all located in the Rocky Mountain region, primarily in the D-J Basin, Powder River Basin, and Green River Basin. During 1996, the Company sold its D-J Basin assets and initiated operations in the Gulf Coast area, primarily offshore in the Gulf of Mexico. As of December 31, 1996, the estimated pre-tax present value of future net revenues from the Company's proved reserves, using year end prices held constant and a discount rate of 10%, totaled $83,656,000 and was distributed as follows: Powder River Basin - 58%; Green River Basin - 14%; other onshore - 9%; Gulf of Mexico - 19%.
Powder River Basin
At December 31, 1996, developed reserves accounted for 55% of the Company's total estimated proved reserve quantities in the Powder River Basin, and 72% of the related pre-tax present value of future net revenues. Approximately 92% of such proved reserves were concentrated in three fields: Scott, Well Draw, and Jepson-Holler Draw. At the end of 1996, the Company owned interests in 224 producing wells and in another 71 locations attributed proved undeveloped reserves within these fields. The Jepson-Holler Draw Field was unitized in 1996 for purposes of initiating secondary recovery operations in the Shannon formation. Water injection commenced in January 1997 and production response is projected to be evident by late-1998. Most of the proved reserves estimated for Jepson-Holler Draw as of December 31, 1996 were categorized as undeveloped. The primary product produced from most of the Company's Powder River Basin properties is oil, but many of the wells also produce liquids-rich casinghead gas generally requiring processing for marketing. Proved reserves are distributed broadly among the wells and locations in these fields, such that no individual well or location accounts for a material portion of aggregate quantities attributed to these properties. Most of the Company's producing wells in the Powder River Basin have been online for several years and production declines are relatively well established. The Company had one development well in the Scott Field in process at December 31, 1996 and anticipates drilling 10 to 12 development wells on its Powder River Basin properties in 1997.
Green River Basin
At December 31, 1996, 76% of the Company's estimated proved reserve quantities in the Green River Basin and 83% of related pre-tax present value of future net revenue were proved developed. Approximately 92% of such proved reserve quantities were associated with the Bird Canyon, Scott Hill, and Horn Canyon fields. At the end of 1996, the Company held interests in 11 producing wells and five proved undeveloped locations within these fields. Scott Hill Field produces oil, whereas the Bird Canyon and Horn Canyon Fields produce predominantly gas. The producing wells in these fields have been on line for several years and generally exhibit stable performance histories, with established decline rates.
Gulf of Mexico
The Company's proved reserves in the Gulf of Mexico at December 31, 1996 were all categorized as undeveloped but related to logged pay sands that were behind-pipe. These reserves were attributable to two exploratory wells drilled in the fourth quarter of the year on Eugene Island (EI) Block 64 and EI Block 65, respectively. The EI 64 well was completed in a secondary objective after a deeper primary- objective sand was found nonproductive. The well has been suspended pending completion and tie-in to a nearby platform operated by a third party. The more significant apparent discovery was made on EI 65 where the #1 well was drilling over year-end 1996. Estimated proved reserves were ultimately attributed to two primary-objective pay sands in this well, but reported year end reserves pertained only to the shallower horizon, since the deeper zone was penetrated and logged in 1997. A second well is currently drilling on EI 65. It is anticipated that a production platform and facilities will be installed on the block later in 1997 to commence production from a dually-completed #1 well, and if successful the #2 well. The Company increased its interests in EI Blocks 64 and 65 in February 1997 as part of an acquisition. See "Present Activities" and "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources."
Additional information related to the Company's properties is set forth below in the balance of this section.
ACREAGE
The following table sets forth the gross and net acres of developed and undeveloped oil and gas leases held by the Company as of December 31, 1996. Undeveloped acreage includes leasehold interests which may already have been classified as containing proved undeveloped reserves.
OIL AND GAS RESERVES
Basin engaged independent petroleum engineers, Netherland, Sewell & Associates, Inc. ("Netherland Sewell"), to audit Basin's estimates of total proved reserves, projected future production, and estimated future net revenues from production of proved reserves for the Company's onshore properties as of December 31, 1996. Basin engaged Ryder Scott Company Petroleum Engineers to prepare such estimates for the Company's offshore properties as of such date. These estimates were based upon a review of production histories and other geologic, economic, ownership, volumetric and engineering data. In determining the estimates of the reserve quantities that are economically recoverable, oil and gas prices and estimated development and production costs as of December 31, 1996 were utilized.
The following table sets forth estimates as of December 31, 1996 derived from Basin's reserve reports. The present values (discounted at 10 percent) of estimated future net revenues before income taxes shown in the table are not intended to represent the current market value of the estimated oil and gas reserves owned by Basin. For further information concerning the present value of future net revenue from these proved reserves, see Unaudited Supplemental Oil and Gas Reserve Information in the Consolidated Financial Statements.
The following table sets forth estimates of Basin's total proved reserves at December 31, 1996 by geographic area of operations:
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth herein represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment and the existence of development plans. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including geologic success, prices, future production levels and cost, that may not prove correct over time. Predictions about prices and future production levels are subject to great uncertainty, and the meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Oil and gas prices have fluctuated widely in recent years. There is no assurance that prices will not be materially higher or lower than the prices utilized in estimating Basin's reserves.
The weighted average sales prices utilized for purposes of estimating Basin's proved reserves and future net revenues therefrom as of December 31, 1996 were $25.35 per Bbl for oil and $3.02 per Mcf for gas. These prices are significantly above average prices prevailing during most of the past several years, and oil and gas prices have declined from such levels during the first two months of 1997.
PRODUCTION
The following table sets forth Basin's net oil and gas production, average sales prices, and costs and expenses associated with such production during the periods indicated.
Basin owned 363 gross (229 net) producing oil wells and 57 gross (39 net) producing gas wells as of December 31, 1996. A well is categorized under state reporting regulations as an oil well or a gas well based upon the ratio of gas to oil produced when it first commenced production, and such designation may not be indicative of current production.
DEVELOPMENT, EXPLORATION AND ACQUISITION EXPENDITURES
The following table sets forth certain information regarding the costs incurred by Basin in its development, exploration and acquisition activities during the periods indicated.
DRILLING ACTIVITY
The following table sets forth the wells drilled and completed by Basin during the periods indicated.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
RESULTS OF OPERATIONS - YEARS ENDED DECEMBER 31, 1996 AND 1995
REVENUE. Excluding a $22,472,000 gain on sale of assets recognized during 1996, revenue for 1996 was $19,191,000, representing a decrease of $21,285,000, or 53%, as compared to 1995. The following table reflects the Company's average oil and gas prices and its average daily oil and gas production for the years presented:
YEAR ENDED DECEMBER 31, ----------------------- 1996 1995 % CHANGE Average price: Oil (per bbl). . . $20.03 $17.02 18 Gas (MMcf) . . . . $ 1.44 $ 1.56 (8)
Average daily production: Oil (bbl). . . . . 1,540 3,160 (51) Gas (Mcf). . . . . 13,050 35,154 (63)
The decreases in average daily production were primarily attributable to the combined effects of sales of producing properties during 1996 and 1995 and natural production declines. As more fully described below under Liquidity and Capital Resources, the Company consummated two transactions during 1996 in which all of its assets in the D-J Basin were sold. As of December 31, 1995, these assets represented approximately two-thirds of the Company's producing wells and 70% of its proved oil and gas reserves. In conjunction with the second transaction, the Company recognized a $22,472,000 gain. Excluding production and sales from such D-J Basin properties, average oil and gas prices and average daily oil and gas production for the periods presented were:
YEAR ENDED DECEMBER 31, ----------------------- 1996 1995 % CHANGE Average price: Oil (per bbl). . . $20.32 $17.61 15 Gas (per Mcf). . . $1.33 $1.09 22
Average daily production: Oil (Bbl). . . . . 1,118 1,341 (17) Gas (Mcf). . . . . 4,871 5,517 (12)
During 1995, the Company also recognized gas revenue for payments received with respect to transferred Section 29 tax credits in the amount of $2,857,000.
Other revenue in 1995 was primarily derived from a small processing facility that was decommissioned late in the year. In 1996, other revenue related mainly to interest income on cash equivalents held after the second D-J Basin asset sale transaction.
LEASE OPERATING EXPENSES. Lease operating expenses for 1996 were $4,776,000, a decrease of $3,420,000, or 42%, compared to 1995. Lease operating costs per Mcfe produced during 1996 averaged $.59 compared to $.42 in 1995. These higher costs per Mcfe were caused primarily by the increased portion of the Company's total active wells that are oil wells, with typically higher unit operating costs, following the sale of the D-J Basin assets.
PRODUCTION TAXES. Production taxes for 1996 were $1,829,000, a decrease of $1,649,000, or 47%, compared to 1995. Production taxes as a percent of oil and gas sales for 1996 were 10.1%, compared to 8.8% in 1995. The increased average tax rate was due to a greater portion of sales occurring in higher-tax jurisdictions in 1996.
DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and amortization expense for 1996 was $7,606,000, a decrease of $9,596,000, or 56%, as compared to 1995. The decrease was primarily attributable to the lower production volumes
in 1996 as compared to 1995. The depletion rate of $.82 per Mcfe produced in 1996 was slightly lower than the $.84 per Mcfe average depletion rate during 1995.
PROPERTY IMPAIRMENT. During 1995, the Company recognized a property impairment charge of $26.5 million, as the result of the capitalized costs of its oil and gas properties exceeding a "ceiling" on such costs computed in accordance with prescribed accounting guidelines.
GENERAL AND ADMINISTRATIVE, NET. General and administrative expenses for 1996 were $3,850,000, a decrease of $1,648,000, or 30%, as compared to 1995. The decreases resulted primarily from staff reductions made during the second half of 1995 and the first half of 1996 and partially due to reductions in office rent expense as a result of relocating and decreasing the size of the corporate headquarters.
INTEREST EXPENSE. Interest expense for 1996 totaled $2,254,000 representing a decrease of $4,178,000, or 65%, as compared to 1995. The decrease was principally attributable to lower average borrowings as a result of asset sales proceeds applied to debt retirement during 1996, as summarized below:
YEAR ENDED DECEMBER 31, ----------------------- 1996 1995
Average borrowings (in thousands) $ 28,200 $ 78,800
Average interest rate on borrowings 8.0% 7.3%
INCOME TAX BENEFIT (PROVISION). The difference between the income tax provision for 1996 and the income tax benefit for 1995, and the amounts that would be calculated by applying statutory income tax rates to income before income taxes is due primarily to the 1996 reversal of the $2,196,000 deferred tax asset valuation allowance established during 1995.
RESULTS OF OPERATIONS - YEARS ENDED DECEMBER 31, 1995 AND 1994
REVENUE. Revenue for 1995 was $40,476,000, a decrease of $3,911,000, or 9%, as compared to 1994. The following table reflects the Company's average oil and gas prices and its average daily oil and gas production for the years presented:
YEAR ENDED DECEMBER 31, ----------------------- 1996 1995 % CHANGE Average price: Oil (per bbl). . . $17.02 $15.63 9 Gas (per Mcf). . . $ 1.56 $1.69 (8)
Average daily production: Oil (Bbl). . . . . 3,160 3,501 (10) Gas (Mcf). . . . . 35,154 39,389 (11)
The declines in production are partially attributable to the sale of marginal properties during 1995. Lower production also resulted from normal depletion-related declines that were not fully offset by new drilling and recompletion activities. The Company recognized gas revenues for payments received with respect to transferred Section 29 tax credits, in the amounts of $2,857,000 and $2,123,000 for the years ended December 31, 1995 and 1994, respectively.
LEASE OPERATING EXPENSES. Lease operating expenses for 1995 were $8,196,000, a decrease of $446,000, or 5%, compared to 1994. Lease operating costs per Mcfe produced during 1995 averaged $.42 compared to $.39 in 1994. These higher costs per Mcfe were caused primarily by a decline in the number of new wells brought on line, since such wells typically have relatively high initial production rates, generating average unit production costs that are lower than more mature properties.
PRODUCTION TAXES. Production taxes for 1995 were $3,478,000, an increase of $46,000, or 1%, compared to 1994. Production taxes as a percent of oil and gas sales for 1995 were 8.8%, compared to 7.8% in 1994. The increased average tax rate was due to a greater portion of sales occurring in higher-tax jurisdictions in 1995.
DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and amortization expense for 1995 was $17,202,000, a decrease of $961,000, or 5%, as compared to 1994. The decrease was attributable to the lower production volumes in 1995 as compared to 1994, as the average depletion rate of $.84 per Mcfe produced in 1995 was higher than the $.77 per Mcfe rate in 1994. The increase reflects investment costs per Mcfe of reserves added during the second half of 1994 and in 1995 which were above the Company's historical average, as well as a reduction in estimated proved reserves at December 31, 1995 due, in part, to the effects of using lower gas prices in determining economic production limits.
PROPERTY IMPAIRMENT. During 1995, the Company recognized a property impairment charge of $26.5 million, as the result of the capitalized costs of its oil and gas properties exceeding a "ceiling" on such costs computed in accordance with prescribed accounting guidelines.
GENERAL AND ADMINISTRATIVE, NET. General and administrative expenses for 1995 were $5,498,000, an increase of $857,000, or 18%, as compared to 1994. The increase is primarily due to smaller recoveries from third-party working interest owners and nonrecurring charges of $545,000 related to staff reductions, settlement of a legal dispute, and an unsuccessful corporate acquisition effort. The lower recoveries resulted from the Company's acquisition in late-1994 of additional working interests in certain properties that it operates and reduced billings for drilling and completion overhead due to a less active property development program in 1995. Decreases in gross general and administrative expenses resulting from late-1995 reductions in office staff and other administrative costs had minimal impact in 1995.
INTEREST EXPENSE. Interest expense for 1996 totaled $6,432,000, an increase of $2,814,000, or 78%, as compared to 1994. This increase was due to the combined effects of increased average borrowings and higher interest rates, as summarized below:
YEAR ENDED DECEMBER 31, ---------------------- 1996 1995
Average borrowings (in thousands) $ 78,800 $ 55,600
Average interest rate on borrowings 7.3% 5.7%
INCOME TAX BENEFIT (PROVISION). The difference between the income tax benefit for 1995, and the amount that would be calculated by applying statutory income tax rates to the loss before income taxes is due to the establishment of a $2,196,000 deferred tax asset valuation allowance during 1995.
LIQUIDITY AND CAPITAL RESOURCES
In February 1996, the Company entered into two agreements pursuant to which it sold all of its assets in the D-J Basin, effective January 1, 1996, for an aggregate adjusted sales price of $123.5 million. The sale of approximately one-third of these D-J Basin assets was closed in March 1996 and the sale of the remainder was closed in June 1996. Combined, these transactions resulted in the disposition of two-thirds of the Company's total wells and approximately 70% of its estimated proved oil and gas reserves as of December 31, 1995. A portion of the sales proceeds was used to repay all outstanding long-term debt and the remainder, net of transaction costs, was initially invested in short-term, interest-bearing cash equivalents pending redeployment into new oil and gas investments. The Company's remaining producing properties after the sale were primarily mature oil and gas fields in the Powder River Basin, Green River Basin, and elsewhere in the Rocky Mountain region.
In August 1996, following the sale of the D-J Basin assets, the Company entered into an amended and restated credit agreement with its existing bank group that improved certain terms, including fees and interest rates, applicable under the line of credit. The amended credit agreement provides for the interest rate on borrowings to be determined by reference to either the prime rate or LIBOR, at the Company's election. A varying spread of 0% to 0.5% is added to the prime rate, or 0.625% to 1.25% is applied to LIBOR, based upon the Company's debt-to-capitalization ratio at the time. The credit agreement provides for borrowings to be revolving loans until August 1, 1999, at which time the outstanding balance will be converted into a four-year amortizing term loan. The credit agreement contains various covenants, including ones that could limit the Company's ability to incur other debt, dispose of assets, pay dividends, or repurchase stock. The borrowing base under the revolving credit facility was established at $25 million in August 1996 and is scheduled to be redetermined as of April 30, 1997 and generally thereafter at six month intervals until converted into a term loan. The Company is anticipating that at the next redetermination date the borrowing base will be established at a level at or above the present level of $25 million, but there can be no assurance that this will occur. As of December 31, 1996, there were no borrowings outstanding under the facility. In addition to availability under the credit line, the Company's capital resources at December 31, 1996 included approximately $19.2 million of net working capital, inclusive of $22 million of cash and cash equivalents.
Prior to sale of its D-J Basin assets the Company had a working capital deficit and little unutilized capacity under its revolving credit facility. The D-J Basin asset sales significantly improved the Company's liquidity but also significantly reduced its oil and gas production and, consequently, its operating cash flow. Prior to 1995 the Company's investments in oil and gas properties typically exceeded its cash flow from operating activities, with the excess funded primarily with bank borrowings and proceeds from equity offerings. The Company's total capital expenditures on oil and gas properties totaled $22.8 million in 1996, $15.7 million in 1995, and $66.5 million in 1994. By comparison, cash flows from operating activities before changes in operating assets and liabilities totaled $5.7 million in 1996, $17.1 million in 1995, and $25 million in 1994. The large decline in capital expenditures from 1994 to 1995 was due, in part, to liquidity constraints that developed when declining Rocky Mountain gas prices unfavorably impacted cash flow and borrowing capacity and reduced the number of economically viable development projects within the Company's asset base. The Company's capital expenditures are generally discretionary and activity levels are determined by a number of factors, including oil and gas prices, interest rates, availability of funds, quantity and character of identified investment projects, availability of service providers, and competition. The Company intends to use the improved liquidity resulting from the D-J Basin asset sales to make new investments in oil and gas properties, through acquisition and development of proved properties, exploration, and exploitation of its property base.
The Company had no extraordinary capital expenditure commitments pending at December 31, 1996. However, in February 1997 the Company acquired, for $14.4 million, interests in three Gulf of Mexico lease blocks with recently drilled wells that were attributed proved reserves but which required additional development to commence production. Development plans for these properties are discussed later in this section. Also, on March 5, 1997 the Company participated in winning bids for 11 tracts at the central Gulf of Mexico lease sale held by the federal government's Minerals Management Service (MMS). If all 11 tracts are awarded by the MMS, which can choose to reject all bids for a given lease, the Company's net share of the related leasehold bonuses will total approximately $5.7 million.
During the past several years the Company has been increasing its capital expenditures on exploration activities. Exploration activities generally have greater investment risk but a higher targeted rate of return than acquisition and development activities. The range of possible investment outcomes is ordinarily much greater for exploration than for other oil and gas investments. In 1996 the Company began focusing its exploration activities in the shallow waters of the Gulf of Mexico, offshore Louisiana and Texas. The Company had conducted no previous operations in the area and began the period with no prospect inventory. To conduct its Gulf Coast exploration activities the Company formed a Houston office staffed with experienced Gulf Coast geoscientists, engineers, and support personnel. During its initial year of operations in the Gulf Coast area the Company invested approximately $14.9 million in related exploration activities, including costs relating to leaseholds that were unproved at December 31, 1996 but net of $4.9 million of costs recouped through resale of partial interests in prospects to industry partners. Such investments primarily related to acquisitions of seismic data and mineral leaseholds, and participation in drilling four exploratory wells, two of which were successful. Because the successful wells were drilled late in the year, the Company did not incur significant related development costs in 1996. The Company's exploration plans for 1997 anticipate participation in five to ten new exploratory test wells, but only one such well has yet been scheduled and the actual number of test wells drilled may be more or less than anticipated.
The two successful wells noted above were drilled on Eugene Island (EI) Blocks 64 and 65, respectively. Both wells were attributed proved reserves as of December 31, 1996 but were categorized as undeveloped at that date because substantial future operations were required in order to make the wells capable of production. The EI 64 #1 well is expected to commence production in the second quarter of 1997 after completion and tie-in to a nearby production platform owned and operated by a third party. It is expected that a production platform will be installed on the EI 65 property in the third quarter of 1997 to produce the #1 well and, if it is successful, the #2 well which is currently drilling.
Through the $14.4 million acquisition consummated in February 1997, the Company increased its interests in EI Blocks 64 and 65. The third property acquired was an interest in East Cameron (EC) Block 378. A well on EC 378 was completed subsea in January 1997 and is waiting on pipeline installation to connect to a nearby third party production platform. Initial production from EC 378 is expected to commence during the third or fourth quarter of 1997.
The Company's capital budget for calendar 1997, excluding acquisitions not already consummated, is approximately $55 million, allocated as follows: approximately $15 million is provided for acquisitions of proved properties; approximately $20 million is provided for acquisitions of prospect leaseholds, seismic data procurement, and exploratory drilling costs; approximately $15 million relates to anticipated development of the Company's existing property base, including EI 64, EI 65, EC 378, and the Company's Rocky Mountain assets; and approximately $5 million is provided for other activities, including current year development of assumed exploratory discoveries. Much of this budget is dependent on future developments that are not entirely within the Company's control and which may not occur. The Company's actual capital expenditures may vary significantly from these estimates. Further, the Company intends to continue to pursue acquisitions of proved properties, primarily in the Gulf Coast and Rocky Mountain regions, which, while not budgeted, could be very significant.
Management believes that the current-year budget, as described above, can be funded without new sources of capital, by utilizing net working capital at the beginning of the period, projected cash flow, and borrowings under the revolving credit facility with the Company's bank group. Cash flow is expected to increase significantly during the latter part of the year when EI 64 and 65 and EC 378 are projected to be on-line; however, these properties have not produced before and the forecast on-line dates and production rates may not be achieved. If conditions warrant, the Company may consider raising additional capital through issuance of debt or equity securities. Should the Company undertake a large acquisition, issuing such securities or monetizing assets would likely be required to fund the transaction. In the absence of additional liquidity, the Company's ability to fund investment activities in future periods will be significantly affected by the results obtained from investments made in 1997.
Changes In Prices
The Company's revenue, cash flow, and the value of its oil and gas properties have been, and will continue to be, affected by changes in oil and natural gas prices. The Company's ability to maintain current borrowing capacity and to obtain additional capital on attractive terms is also substantially dependent on oil and natural gas prices. As such, changes in oil and gas prices can significantly affect the amount of the Company's capital expenditures. Oil and natural gas prices are subject to significant seasonal and other fluctuations that are beyond the Company's ability to control or predict. The Company periodically enters into product swap agreements in order to hedge against the volatility of product prices. Although the Company enters into the agreements to limit exposure to price decreases, the agreements also limit the Company's ability to benefit from significant price increases on the contract volumes. Effective July 1, 1996, the Company entered into a crude oil swap agreement with a contract volume of 10,000 barrels per month through December 31, 1997. This agreement provides for the cash settlement of the differential between the $18.32 per barrel contract price and the average closing NYMEX crude oil price during each month. The Company has also entered into a crude oil collar arrangement effective for calendar 1997 on an additional 10,000 barrels per month. This agreement provides for the cash settlement of the differential between the monthly average closing NYMEX price and the contract floor of $19.50 per barrel or the contract ceiling of $24.35 per barrel, if the average monthly NYMEX price falls outside of the range defined by such contract floor and contract ceiling. Any gain or loss realized on these agreements is included as a component of oil sales in the month of production.
CERTAIN FACTORS THAT MAY AFFECT FUTURE RESULTS
Statements that are not historical facts contained in this report are forward-looking statements that involve risks and uncertainties that could cause actual results to differ from projected results. Such statements address activities, events or developments that the Company expects, believes, projects, intends or anticipates will or may occur, including such matters as future capital, development and exploration expenditures (including the amount and nature thereof), drilling of wells, reserve estimates (including estimates of future net revenues associated with such reserves and the present value of such future net revenues), future production of oil and gas, business strategies, expansion and growth of the Company's operations, cash flow and anticipated liquidity, prospect development and property acquisition, obtaining financial or industry partners for prospect or program development, or marketing of oil and gas. Factors that could cause actual results to differ materially ("Cautionary Disclosures") are described, among other places, in the Marketing, Competition, and Regulation sections in this Form 10-K and under the caption "Management's Discussion and Analysis of Financial Condition and Results of Operations." Without limiting the Cautionary Disclosures so described, Cautionary Disclosures include, among others: general economic conditions, the market price of oil and natural gas, the risks associated with exploration, the Company's ability to find, acquire, market, develop and produce new properties, operating hazards attendant to the oil and natural gas business, the Company's inexperience in the Gulf of Mexico, uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures, the strength and financial resources of the Company's competitors, the Company's ability to find and retain skilled personnel, climatic conditions, labor relations, availability and cost of material and equipment, delays in anticipated start-up dates, environmental risks, the results of financing efforts, and regulatory developments. All written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Disclosures, including without limitation those contained in the President's letter contained in the Annual Report to Stockholders. The Company disclaims any obligation to update or revise any forward- looking statement to reflect events or circumstances occurring hereafter or to reflect the occurrence of anticipated or unanticipated events.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The Consolidated Financial Statements that constitute Item 8 are attached at the end of this report. An index to the Consolidated Financial Statements appears in Item 14(a) of this report.
ITEM 9. CHANGES AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The information required by this item is incorporated by reference from the sections entitled "Management" and "Disclosure of Filings by Insiders" 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. 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, which are expressly not incorporated herein.
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. 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.
CERTAIN DEFINITIONS
The terms defined in this section are used throughout this report.
Acreage held by production. Acreage covered by an oil and gas lease which has a producing well on it, or which is pooled with a lease or leases having one or more producing wells on them, so the lease is maintained in effect for the duration of such production.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
Bcf. Billion cubic feet (of gas).
Bcfe. Billion cubic feet (of gas) equivalent.
Behind-pipe reserves. Proved reserves in a formation in which production casing has already been set in the wellbore, but from which production has not commenced.
Btu. British thermal unit.
Commingle. The combining of production from more than one zone in the same well to produce from multiple zones at the same time.
Development location. A location on which a development well can be drilled.
Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive in an attempt to recover proved undeveloped reserves.
Drilling locations. A site on which a well can be drilled consistent with local spacing rules for the purpose of recovering possible, probable or proved reserves.
Dry well. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
Exploitation. The conduct of a drilling or recompletion operation intended to recover reserves from a formation known to be productive in the area or on trend with existing production but not classifiable as proved.
Exploratory well. A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir.
Farmout. An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location.
Gross acres. An acre in which a working interest is owned.
Gross well. A well in which a working interest is owned.
MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.
MBtu. One thousand Btus.
Mcf. One thousand cubic feet (of gas).
Mcfe. One thousand cubic feet of natural gas equivalent. In reference to crude oil or other liquid hydrocarbons, equivalents are determined using the ratio of one Bbl of crude oil or other liquid hydrocarbon to 6 Mcf of gas.
MMBbl. One million barrels of crude oil or other liquid hydrocarbons.
MMBtu. One million Btus.
MMcf. One million cubic feet.
MMcfe. One million cubic feet (of gas) equivalent.
Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells.
Overriding royalty interest. An interest in an oil and gas property entitling the owner to a share of oil and gas production free of costs of production.
Present value of future net revenues. Estimated future net revenues discounted at a rate of ten percent per annum.
Productive well. A well that is producing oil or gas or that is capable of production.
Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved undeveloped location. A site on which a development well can be drilled consistent with local spacing rules for the purpose of recovering proved reserves.
Proved undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Recompletion. The completion for production of an existing wellbore in another formation from that in which the well has previously been completed.
Undeveloped acreage. Lease acreage 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 such acreage contains proved reserves.
Working interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules
PAGE
Report of Independent Public Accountants . . . . . . . . . . . . .
Consolidated Statements of Operations for the years ended December 31, 1996, 1995, and 1994 . . . . . . . . . . . . . .
Consolidated Balance Sheets as of December 31, 1996 and 1995 . . .
Consolidated Statements of Cash Flow for the years ended December 31, 1996, 1995 and 1994. . . . . . . . . . . .
Consolidated Statements of Changes in Stockholders' Equity for the years ended December 31, 1996, 1995 and 1994. . . . .
Notes to Consolidated Financial Statements . . . . . . . . . . . .
All other schedules are omitted because the required information is not applicable or is not present in amounts sufficient to require submission of the schedule or because the information required is included in the Combined Financial Statements and Notes thereto.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders and Board of Directors of Basin Exploration, Inc.:
We have audited the accompanying consolidated balance sheets of Basin Exploration, Inc., and subsidiaries, as of December 31, 1996 and 1995, and the related consolidated statements of operations, changes in stockholders' equity and cash flow for each of the three years in the period ended December 31, 1996. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated finan- cial 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 consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Basin Exploration, 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.
/s/ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP
Denver, Colorado, February 14, 1997.
BASIN EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS
BASIN EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
BASIN EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS--(Continued)
BASIN EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOW
BASIN EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOW--(CONTINUED)
BASIN EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
BASIN EXPLORATION, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES ------------------------------------------
Organization and Operations -- The consolidated financial --------------------------- statements include the financial statements of Basin Exploration, Inc. and its wholly owned subsidiaries,(collectively referred to as "Basin" or the "Company"). Basin, as operator of jointly owned oil and gas properties, sells a significant amount of such production to certain major customers (see Note 9), and pays vendors for oil and gas services. Joint interest receivables are subject to collection under terms of operating agreements which generally provide lien rights.
The accompanying financial statements present the operations of the Company on a consolidated basis. All significant intercompany accounts and transactions have been eliminated in consolidation. 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.
Certain reclassifications have been made to amounts reported in previous years to conform to 1996 presentation.
Cash Equivalents -- Cash equivalents are comprised of highly ---------------- liquid instruments with original maturities of three months or less. The total carrying amount of cash and equivalents approximates the fair value of such instruments.
Oil and Gas Properties -- The Company follows the full cost ---------------------- method of accounting for oil and gas properties. Under this method, all costs associated with the development, exploration and acquisition of oil and gas properties are capitalized in the Company's one cost center (full cost pool), which is the continental United States including the Gulf of Mexico. Payroll and other internal costs capitalized include salaries and related fringe benefits paid to employees directly engaged in the acquisition, exploration and development of oil and gas properties as well as all other directly identifiable, internal costs associated with these activities. Payroll and other internal costs associated with production operations and general corporate activities are expensed in the period incurred. Future development, site restoration, dismantlement and abandonment costs, net of salvage values, are estimated on a property-by- property basis based on prevailing prices and are amortized to expense, along with the capitalized costs discussed above, using the unit-of-production method based upon actual production and estimates of proved reserve quantities. Accumulated depreciation, depletion and amortization is recorded on the balance sheet as a reduction to property, plant and equipment costs. Proceeds from sales of oil and gas properties are credited to the full cost pool with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas.
If capitalized costs, net of amortization and related deferred taxes, exceed the full cost ceiling, the excess would be expensed in the period such excess occurs. The full cost ceiling includes an estimate of the discounted value of future net revenues attributable to proven reserves, using various assumptions and parameters consistent with promulgations of the Securities and Exchange Commission. The full cost ceiling may be particularly sensitive to changes in prevailing oil and gas sales prices or forecast production rates. The Company recognized $26,500,000 of such impairment at September 30, 1995.
The Company invests in unevaluated oil and gas properties and related assets for the purpose of future exploration for proved reserves. The costs of such assets are included in unproved oil and gas properties at the lower of cost or estimated fair market value.
Inventory -- Inventory of lease and well equipment is stated --------- at the lower of cost or market determined using the specific identification method.
Furniture and Equipment -- Furniture and equipment is ----------------------- depreciated over estimated useful lives of five to seven years. Maintenance and repair costs are expensed as incurred.
BASIN EXPLORATION, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Income Taxes -- The Company computes income taxes in ------------ accordance with Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes." SFAS 109 requires an asset and liability approach which results in the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the carrying amounts and the tax bases of those assets and liabilities. SFAS 109 also requires the recording of a valuation allowance if it is more likely than not that some portion or all of a deferred tax asset will not be realized.
Hedging Activities -- The Company periodically enters into ------------------ agreements with third parties to hedge against the effects of fluctuations in future oil and gas prices. Gains or losses on such agreements are deferred and recognized as oil and gas revenue when the hedged production occurs.
At December 31, 1996, the Company was a party to a crude oil swap agreement and a crude oil collar arrangement, each with a contract volume of 10,000 barrels per month through December 31, 1997. The swap agreement provides for the cash settlement of the differential between the $18.32 per barrel contract price and the average closing NYMEX crude oil price during each month. The collar arrangement provides for the cash settlement of the differential between the monthly average closing NYMEX price and the contract floor of $19.50 per barrel or the contract ceiling of $24.35 per barrel, if the monthly average closing NYMEX price falls outside of the range defined by such contract floor and contract ceiling. In accordance with SFAS 107, "Disclosures About Fair Value of Financial Instruments," the Company has estimated the fair value of its hedging arrangements utilizing the NYMEX crude oil strip at December 31, 1996. While it is not the Company's intention to terminate either of the arrangements, it is estimated that the Company would have been required to pay approximately $525,000 to terminate the arrangements on December 31, 1996. As of February 12, 1997, the estimated cost to terminate such arrangements was approximately $325,000, inclusive of the actual cost of contract settlements through that date. Due to the volatility of crude oil prices, the fair market value may not be representative of the actual gain or loss that will be realized by the Company in 1997.
The Company recognized a reduction in oil revenue of $480,000, $115,000 and $95,000 under hedging agreements in 1996, 1995 and 1994, respectively. The Company recognized a reduction in gas revenue of $206,000 under hedging agreements in 1994.
Earnings (Loss) Per Share -- Earnings (loss) per share have ------------------------- been computed based on the weighted average number of common shares outstanding. The impact of dilutive common stock equivalents on earnings (loss) per share was immaterial.
(2) RESTRICTED CASH ---------------
Well Plugging -- The Company was required under a certain ------------- farmout agreement to deposit in an escrow account amounts for future plugging and abandonment costs beyond a one-year time period. The total cash held in escrow at December 31, 1995, was $578,000. Such escrow account was closed and the funds were released to the Company in November 1996.
(3) ACQUISITIONS AND DIVESTITURES OF OIL AND GAS PROPERTIES -------------------------------------------------------
In February 1996, the Company entered into agreements pursuant to which it sold all of its assets in the D-J Basin in two transactions closed in March and June 1996, for an aggregate sales price of $123,500,000, effective January 1, 1996. Combined, these transactions resulted in Basin selling its interests in approximately two-thirds of its producing wells and 70% of its proved oil and gas reserves at December 31, 1995. Because the second transaction constituted the sale of a significant portion of the Company's total oil and gas reserves which would significantly alter the relationship between the Company's capitalized costs and its proved reserves, net capitalized costs of oil and gas properties were allocated between the reserves sold and retained based upon their estimated relative reserve quantities as of June 7, 1996 and a resulting gain of approximately $22,500,000 was recognized. A portion of the proceeds from the sales was used to payoff all outstanding bank debt and residual proceeds, net of transaction costs, were invested in short-term interest bearing cash equivalents. Revenue and expenses associated with the sold properties were included in the Company's results of operations through the respective closing dates.
BASIN EXPLORATION, INC AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
In November 1994 the Company acquired all of the outstanding stock of Sterling Energy Corp. ("Sterling") for aggregate consideration of approximately $15.4 million consisting of approximately $10.1 million in cash, the assumption of $3.6 million of net liabilities, warrants to purchase 300,000 shares of the Company's common stock at an exercise price of $14.00 valued at $1.5 million, and $.2 million in transaction expenses. The acquisition included producing and non-producing oil and gas properties and undeveloped acreage located in the Scott and Draw fields in Converse County, Wyoming and in the Tohonadla field in San Juan County, Utah, as well as a gas processing plant located in Wyoming. The acquisition was funded partially with an increased revolving credit facility. The Company accounted for the Sterling acquisition using purchase accounting and began consolidating the results as of the December 1994 close date.
(4) LONG-TERM DEBT --------------
On August 6, 1996, the Company entered into an Amended and Restated Credit Agreement with its existing bank group. The initial borrowing base was set at $25,000,000 and is scheduled to be determined as of April 30, 1997 for the following six month period. The Credit Agreement provides for the interest rate on borrowings to be determined based on the prime rate or LIBOR, at the Company's election. A varying spread above the prime rate ranging from 0% to 0.5% and over LIBOR ranging from 0.625% to 1.25% will be applied based upon the Company's applicable debt- to-capitalization ratio. The Credit Agreement provides for borrowings to be revolving loans until August 1, 1999, at which time the outstanding balance is scheduled to convert to a four year amortizing term loan. The Credit Agreement contains various covenants, including ones that could limit the Company's ability to incur other debt, dispose of assets, pay dividends or repurchase stock. The note may be secured by the Company's oil and gas properties in certain circumstances, at the election of the lending banks. There were no borrowings outstanding under the facility at December 31, 1996.
Effective May 31, 1995, in order to improve management of interest rate risk, Basin entered into an interest rate swap agreement. Under the agreement, the Company fixed the LIBOR reference rate on a notional amount of $50 million at 6 percent per annum through May 31, 1996.
Debt is payable as follows:
(5) BENEFIT PLANS -------------
401(k) Savings -- The Company has a 401(k) profit sharing -------------- plan (the "Plan"). Eligible employees may make voluntary contributions to the Plan, which may be matched by the Company, at its discretion, up to 6 percent of the employee's eligible compensation. The Company has historically matched the first three percent of employees' eligible compensation that is contributed under the Plan. The amount of employee contributions is limited as specified in the Plan. The Company may, at its discretion, make additional contributions to the Plan. The Company expensed $96,000, $195,000, and $261,000, with respect to the Plan for the years ended December 31, 1996, 1995 and 1994, respectively.
BASIN EXPLORATION, INC AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Stock Plan -- Under the Company's Employees' Equity ---------- Incentive Plan and Non-Employee Directors' Stock Option Plan, officers, key employees, consultants and directors of the Company are eligible to receive incentive stock options, non-qualified stock options and restricted stock. At December 31, 1996, a total of approximately 1,365,000 shares were available for grant under the plans. Shares granted generally vest over three to four years, and expire after ten years. A total of 684,000 shares of the Company's common stock are subject to such plans as of December 31, 1996, including 35,000 unvested shares of restricted stock and 649,000 outstanding stock options.
The following table summarizes the changes in stock options:
At December 31, 1996, the weighted average exercise price and weighted average remaining life for options outstanding was $6.55 per share and 8.3 years, respectively. Additional information regarding the outstanding options at December 31, 1996, is as follows.
In connection with its initial public offering ("IPO") in 1992, the Company granted options to two officers to purchase 100,000 shares each of the Company's common stock at a price substantially below the IPO price of $9.50 per share. The Company recognized compensation expense related to these options of approximately $97,000 and $233,000 for the years ended December 31, 1995 and 1994, respectively.
The Company granted 25,000, 32,000, and 25,000 shares of restricted stock during 1996, 1995 and 1994, respectively. Related compensation expense was recognized in the amounts of approximately $98,000, $205,000, and $121,000 for the years ended December 31, 1996, 1995, and 1994, respectively. Cumulatively through December 31, 1996, 35,000 shares of restricted stock remained subject to forfeiture, 48,000 shares of restricted stock had been forfeited and 42,000 shares were no longer subject to restriction.
In connection with the Sterling acquisition, the Company issued warrants to purchase 300,000 shares of the Company's common stock at an exercise price of $14.00 per share. Such warrants became exercisable on October 13, 1994 and have an expiration date of December 31, 1999.
In October 1995, the Financial Accounting Standards Board issued SFAS 123, "Accounting for Stock-Based Compensation." SFAS 123 was effective for 1996 and recommends a fair value based method of accounting for employee stock compensation, including stock options. However, companies may choose to account for stock compensation using the intrinsic value based method as prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" and provide pro forma disclosures of net income and earnings per share as if the fair value based method had been applied. The Company has elected to continue to account for stock compensation using the intrinsic value based method.
BASIN EXPLORATION, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS --(CONTINUED)
Had the Company elected to follow SFAS 123, the fair value of each option grant would have been estimated on the date of grant using the Black-Sholes option-pricing model with the following weighted-average assumptions used for grants in 1996 and 1995: risk free interest rate of 6.75%; expected dividend yield of 0%; expected life of 5 years; and expected volatility of 55%. Based upon these assumptions, the weighted average fair value of options granted during 1996 and 1995 was $2.73 and $2.96 per share, respectively. SFAS 123 would have had no significant impact on reported operating results for the years ended December 31, 1996 and 1995.
(6) COMMITMENTS AND CONTINGENCIES -----------------------------
Leases -- The Company is the primary obligor under various ------ noncancelable office space operating lease arrangements. The Company also subleases certain office space to and from third parties under various noncancellable lease arrangements. The following is a schedule of future minimum lease payments under these leases:
Payments related to these leases obligations were approximately $707,000, $710,000, and $435,000 for the years ended December 31, 1996, 1995 and 1994, respectively.
Legal Proceedings -- The Company, from time to time, is ----------------- involved in various legal and administrative proceedings and claims of various types which arise in the ordinary course of its business. While any litigation contains an element of uncertainty, in the opinion of management, none of these actions, either individually or in the aggregate will have a material adverse effect on results the Company's financial condition, liquidity or results of operations.
(7) INCOME TAXES ------------
The components of the provision (benefit) for income taxes are as follows:
BASIN EXPLORATION, INC AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Reconciliations of income tax provisions (benefit) computed at the federal statutory rate with income tax provisions recorded by the Company for each of the past three years are as follows:
The tax effects of significant temporary differences representing deferred tax assets and liabilities are as follows:
As of December 31, 1996, the Company has alternative minimum tax credit carry forwards for income tax purposes of approximately $1,475,000 which may be utilized to reduce future tax liability of the Company. These carry forwards have no expiration date.
(8) RELATED PARTY TRANSACTIONS --------------------------
Prior to the IPO, the Company advanced $559,000 to its principal stockholder at an annual interest rate of 9 percent. The note was amended in 1996 and the balance is now due in December 1997 with interest only payments due quarterly.
BASIN EXPLORATION, INC AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(9) OIL AND GAS ACTIVITIES ----------------------
The Company's oil and gas operations are conducted in the United States. Certain information concerning these activities follows:
Major Purchasers -- The following parties purchased ten ---------------- percent or more of the Company's oil and gas production.
Purchaser Year ended December 31, 1996 1995 1994 -------------------------------------------------------
PanEnergy 43% 62% 77% Eighty-Eight Oil Company 26% 16% (a)
(a) less than ten percent
Section 29 Tax Credits -- The Company received $1.5 million ---------------------- and $3 million in 1995 and 1994 respectively, for Section 29 tax credits associated with gas production from various oil and gas properties of the Company. Such proceeds were recorded as unearned income and recognized as incremental gas revenues as the gas was produced and the credits earned. The Company recognized approximately $2,857,000 and $2,123,000 of additional gas revenue during the years ended December 31, 1995 and 1994, respectively, related to the amortization of this unearned income.
Costs Incurred -- Costs incurred in oil and gas operations -------------- and related depreciation, depletion and amortization per equivalent unit-of-production are as follows:
Year Ended December 31, 1996 1995 1994 - ---------------------------------------------------------------------- (in thousands)
Property acquisition- Unproved $ 5,056/1/ $ 2,429 $ 5,275 Proved 3,067 3,889 16,751 Exploration costs 10,250 2,003 2,361 Development costs 4,472 7,427 42,113 - ---------------------------------------------------------------------- Gross expenditures $ 22,845 $ 15,748 $ 66,500 ======================================================================
Depletion per one thousand cubic feet of gas equivalent $ 0.82 $ 0.84 $ 0.77 ======================================================================
/1/ Excludes $4,914,000 of costs recouped through the resale of partial interests in prospects to industry partners.
Costs Not Being Amortized -- Oil and gas property costs not ------------------------- being amortized at December 31, 1996, consisted of $9,822,000 of leasehold and seismic costs, of which $9,058,000, $488,000 and $276,000 were incurred in 1996, 1995 and 1994, respectively. The Company anticipates that substantially all unevaluated costs will be classified as evaluated costs within the next three years.
BASIN EXPLORATION, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION - ------------------------------------------------------
The determination of oil and gas reserves is complex and highly interpretive. Assumptions used to estimate reserve information may significantly increase or decrease such reserves in future periods. The estimates of reserves are subject to continuing changes and, therefore, an accurate determination of reserves may not be possible for many years because of the time needed for development, drilling, testing and studies of the reservoirs. The following unaudited table, based upon estimates of onshore reserves prepared by the Company's engineers and audited by Netherland, Sewell & Associates, Inc. at December 31, 1996, 1995 and 1994 and estimates of offshore reserves prepared by Ryder Scott Company Petroleum Engineers at December 31, 1996, sets forth the estimated quantities of proved oil and gas reserves for the Company and the changes in total proved reserves as of December 31, 1996, 1995, and 1994. All such reserves are located in the United States.
ANALYSES OF CHANGES IN PROVED RESERVES - --------------------------------------
STANDARDIZED MEASURE - --------------------
The unaudited standardized measure of discounted future net cash flows related to proved oil and gas reserves are as follows:
December 31, 1996 1995 1994 - ---------------------------------------------------------------------- (in thousands)
Future production revenues $ 289,105 $ 439,415 $ 505,636 Future production costs (108,522) (155,087) (163,244) Future development costs (20,583) (45,907) (49,293) Future income taxes (39,101) (25,644) (45,252) - ---------------------------------------------------------------------- Future net cash flows 120,899 212,777 247,847 Discount (57,593) (95,529) (106,495) - ---------------------------------------------------------------------- Standardized measure of discounted future net cash flows/1/ $ 63,306 $ 117,248 $ 141,352 ======================================================================
/1/ Total future net cash flows before income taxes discounted at 10% per annum are $83,656,000, $129,068,000 and $162,858,000 as of December 31, 1996, 1995 and 1994, respectively.
BASIN EXPLORATION, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS --(CONTINUED)
The estimate of future income taxes is based on the future net cash flows from proved reserves adjusted for the tax basis of the oil and gas properties but without consideration of general and administrative and interest expenses. For standardized measure purposes the Company estimates future income taxes using the "year-by- year" method. For ceiling test purposes the Company estimates future income taxes using the "short-cut" method.
A summary of changes in the standardized measure of discounted future net cash flows is as follows:
There are numerous uncertainties inherent in estimating quantities of proved reserves and projected future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data and standardized measures set forth herein represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including geologic success, prices, future production levels and costs, that may not prove correct over time. Predictions of future production levels are subject to great uncertainty, and the meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Oil and gas prices have fluctuated widely in recent years. The calculated weighted average sales prices utilized for the purposes of estimating the Company's proved reserves and future net revenue were and $25.35 per barrel of oil and $3.02 per Mcf of gas at December 31, 1996, $18.64 per barrel of oil and $1.56 per Mcf of gas at December 31, 1995 and $16.44 per barrel of oil and $1.63 per Mcf of gas at December 31, 1994.
BASIN EXPLORATION, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS --(CONTINUED)
UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA - ----------------------------------------------- (in thousands except per share amounts)(unaudited)
(a)(3) Exhibits
EXHIBIT NUMBER DESCRIPTION OF EXHIBITS ------- -----------------------
2.1 -- Agreement and Plan of Merger between Sterling Energy Corporation, Basin Energy, Inc. and Basin Exploration, Inc. dated October 13, 1994/7/ 2.2 -- Plan of Merger between Basin Sterling, Inc. and Basin Exploration, Inc. dated November 22, 1994/8/ 2.3 -- Plan of Merger between Basin Operating Company and Basin Exploration, Inc. dated December 14, 1994/8/ 3.1 -- Restated Certificate of Incorporation of Basin./2/ 3.2 -- Restated Bylaws of Basin./2/ 4.1 -- Common Stock Certificate of Basin./2/ 10.1 -- Equity Incentive Plan as amended June 6, 1996./1/ 10.2 -- Directors' Stock Option Plan as amended June 6, 1996./1/ 10.3 -- Key Employee Participation Plan./2/ 10.4 -- Employment Agreement dated March 31, 1992 by and between Basin and Michael S. Smith./3/ 10.5 -- Gulf Coast Geoscientist Overriding Royalty Interest Plan dated November 30, 1995./10/ 10.6 -- Form of Rights Agreement dated as of February 24, 1996, between Basin Exploration, Inc. and Corporate Stock Transfer, Inc. as Rights Agent./9/ 10.7 -- Performance Shares Plan approved February 4, 1997./1/ 10.8 -- Change of Control Employment Agreement dated October 13, 1995 between Basin Exploration, Inc. and Howard L. Boigon./10/ 10.9 -- Employment Agreement dated August 28, 1995 between Basin Exploration, Inc. and Samuel D. Winegrad./10/ 10.10 -- Employment Agreement dated June 28, 1995 between Basin Exploration, Inc. and Neil L. Stenbuck./10/ 10.11 -- Employment Agreement dated November 10, 1995 between Basin Exploration, Inc. and David A. Pustka./10/ 10.12 -- Employment Agreement dated February 23, 1996 between Basin Exploration, Inc. and Thomas J. Corley./1/ 10.13 -- Assignment and Assumption of Lease dated December 18, 1995 by and between Team, Inc., as original Tenant, Basin Exploration, Inc., as New Tenant, and FC Tower Property Partners, L.P., as Landlord./9/ 10.14 -- First Supplement to Amended Mortgage, Security Agreement, Assignment, Financing Statement and Fixture Filing dated May 8, 1995 by and between Basin Exploration, Inc. and Basin Gas Ltd. to NationsBank of Texas, N.A., as successor collateral agent for the benefit of Colorado National Bank, Union Bank and NationsBank of Texas, N.A./8/ 10.15 -- Second Supplement to Amended Mortgage, Security Agreement, Assignment, Financing Statement and Fixture Filing dated May 8, 1995 by and between Basin Exploration, Inc., and Basin Gas Ltd. to NationsBank of Texas, N.A. in its capacity as the successor collateral agent for the benefit of Colorado National Bank, Union Bank and NationsBank of Texas, N.A./10/ 10.16 -- Agreement for Purchase and Sale of Assets (Monetization) dated February 24, 1996 by and between Basin Exploration, Inc., HS Resources, Inc. and Orion Acquisition, Inc./7/ 10.17 -- Agreement for Purchase and Sale of Assets (Wattenberg), dated February 24, 1996 by and between Basin Exploration, Inc., HS Resources, Inc. and Orion Acquisition, Inc./7/ 10.18 -- Lease of Office Space dated September 25, 1992, between Brookfield Republic Inc. and Basin Operating Company, as amended/4/* 10.19 -- First Lease of Additional Office Space dated as of December 1, 1994, between Brookfield Republic, Inc. and Basin Operating Company./6/* 10.20 -- Amended and Restated Credit Agreement dated August 6, 1996 between the Company and Colorado National Bank, Union Bank of California, N.A. and NationsBank of Texas, N.A./11/ 10.21 -- Purchase and Sale Agreement dated February 13, 1997, between Hall-Houston Oil Company et al as Sellers and Basin Exploration, Inc. as Buyer./1/** 21 -- Subsidiaries./1/ 23.1 -- Consent of Arthur Andersen LLP/1/ 23.2 -- Consent of Netherland, Sewell & Associates, Inc./1/ 23.3 -- Consent of Ryder Scott Company/1/ 27 -- Financial Data Schedule./1/
- ----------------
/1/ Filed herewith.
/2/ Filed as an Exhibit to Basin's Registration Statement on Form S-1 as filed on March 17, 1992, Registration No. 33-46486, and incorporated herein by reference.
/3/ Filed as an Exhibit to Amendment No. 1 to Basin's Registration Statement on Form S-1 as filed on April 21, 1992, Registration No. 33-46486, and incorporated herein by reference.
/4/ Filed as an Exhibit to Basin's Registration Statement on Form S-1 as filed on October 25, 1993, Registration No. 33-70802, and incorporated herein by reference.
/5/ Filed as an Exhibit to Form 8-K filed on December 10, 1994, and incorporated herein by reference.
/6/ Filed as an Exhibit to Form 10-K/A-1 filed on June 26, 1995 and incorporated herein by reference.
/7/ Filed as an Exhibit to Form 8-K filed on March 6, 1996, and incorporated herein by reference.
/8/ Filed as an Exhibit to Form 10-K filed on March 28, 1995, and incorporated herein by reference.
/9/ Filed as an Exhibit to Form 8-K filed on February 26, 1996, and incorporated herein by reference.
/10/ Filed as an Exhibit to Form 10-K filed on March 28, 1996, and incorporated herein by reference.
/11/ Filed as an Exhibit to Form 10-Q filed on August 14, 1996, and incorporated herein by reference.
* Confidential treatment has been granted for portions of these Exhibits.
** Confidential treatment has been requested for portions of this Exhibit.
(b) Reports on Form 8-K
None
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.
BASIN EXPLORATION, INC.
By: /s/ MICHAEL S. SMITH Date: March 17, 1997 ------------------------------------- Michael S. Smith President, Chief Executive Officer and Chairman of the Board
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.
EXHIBIT INDEX
EXHIBIT NUMBER DESCRIPTION OF EXHIBITS PAGE NO. - ------- ----------------------- --------
10.1 -- Equity Incentive Plan as amended June 6, 1996. 71
10.2 -- Directors' Stock Option Plan as amended June 6, 1996. 90
10.7 -- Performance Shares Plan approved February 4, 1997. 98
10.12 -- Employment Agreement dated February 23, 1996 between Basin Exploration, Inc. and Thomas J. Corley. 107
10.21 -- Purchase and Sale Agreement dated February 13, 1997, between Hall-Houston Oil Company et al as Sellers and Basin Exploration, Inc. as Buyer. 118
21 -- Subsidiaries 157
23.1 -- Consent of Arthur Andersen LLP 158
23.2 -- Consent of Netherland, Sewell & Associates, Inc. 159
23.3 -- Consent of Ryder Scott Company 160
27 -- Financial Data Schedule 161
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
RESULTS OF OPERATIONS - YEARS ENDED DECEMBER 31, 1996 AND 1995
REVENUE. Excluding a $22,472,000 gain on sale of assets recognized during 1996, revenue for 1996 was $19,191,000, representing a decrease of $21,285,000, or 53%, as compared to 1995. The following table reflects the Company's average oil and gas prices and its average daily oil and gas production for the years presented:
YEAR ENDED DECEMBER 31, ----------------------- 1996 1995 % CHANGE Average price: Oil (per bbl). . . $20.03 $17.02 18 Gas (MMcf) . . . . $ 1.44 $ 1.56 (8)
Average daily production: Oil (bbl). . . . . 1,540 3,160 (51) Gas (Mcf). . . . . 13,050 35,154 (63)
The decreases in average daily production were primarily attributable to the combined effects of sales of producing properties during 1996 and 1995 and natural production declines. As more fully described below under Liquidity and Capital Resources, the Company consummated two transactions during 1996 in which all of its assets in the D-J Basin were sold. As of December 31, 1995, these assets represented approximately two-thirds of the Company's producing wells and 70% of its proved oil and gas reserves. In conjunction with the second transaction, the Company recognized a $22,472,000 gain. Excluding production and sales from such D-J Basin properties, average oil and gas prices and average daily oil and gas production for the periods presented were:
YEAR ENDED DECEMBER 31, ----------------------- 1996 1995 % CHANGE Average price: Oil (per bbl). . . $20.32 $17.61 15 Gas (per Mcf). . . $1.33 $1.09 22
Average daily production: Oil (Bbl). . . . . 1,118 1,341 (17) Gas (Mcf). . . . . 4,871 5,517 (12)
During 1995, the Company also recognized gas revenue for payments received with respect to transferred Section 29 tax credits in the amount of $2,857,000.
Other revenue in 1995 was primarily derived from a small processing facility that was decommissioned late in the year. In 1996, other revenue related mainly to interest income on cash equivalents held after the second D-J Basin asset sale transaction.
LEASE OPERATING EXPENSES. Lease operating expenses for 1996 were $4,776,000, a decrease of $3,420,000, or 42%, compared to 1995. Lease operating costs per Mcfe produced during 1996 averaged $.59 compared to $.42 in 1995. These higher costs per Mcfe were caused primarily by the increased portion of the Company's total active wells that are oil wells, with typically higher unit operating costs, following the sale of the D-J Basin assets.
PRODUCTION TAXES. Production taxes for 1996 were $1,829,000, a decrease of $1,649,000, or 47%, compared to 1995. Production taxes as a percent of oil and gas sales for 1996 were 10.1%, compared to 8.8% in 1995. The increased average tax rate was due to a greater portion of sales occurring in higher-tax jurisdictions in 1996.
DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and amortization expense for 1996 was $7,606,000, a decrease of $9,596,000, or 56%, as compared to 1995. The decrease was primarily attributable to the lower production volumes
in 1996 as compared to 1995. The depletion rate of $.82 per Mcfe produced in 1996 was slightly lower than the $.84 per Mcfe average depletion rate during 1995.
PROPERTY IMPAIRMENT. During 1995, the Company recognized a property impairment charge of $26.5 million, as the result of the capitalized costs of its oil and gas properties exceeding a "ceiling" on such costs computed in accordance with prescribed accounting guidelines.
GENERAL AND ADMINISTRATIVE, NET. General and administrative expenses for 1996 were $3,850,000, a decrease of $1,648,000, or 30%, as compared to 1995. The decreases resulted primarily from staff reductions made during the second half of 1995 and the first half of 1996 and partially due to reductions in office rent expense as a result of relocating and decreasing the size of the corporate headquarters.
INTEREST EXPENSE. Interest expense for 1996 totaled $2,254,000 representing a decrease of $4,178,000, or 65%, as compared to 1995. The decrease was principally attributable to lower average borrowings as a result of asset sales proceeds applied to debt retirement during 1996, as summarized below:
YEAR ENDED DECEMBER 31, ----------------------- 1996 1995
Average borrowings (in thousands) $ 28,200 $ 78,800
Average interest rate on borrowings 8.0% 7.3%
INCOME TAX BENEFIT (PROVISION). The difference between the income tax provision for 1996 and the income tax benefit for 1995, and the amounts that would be calculated by applying statutory income tax rates to income before income taxes is due primarily to the 1996 reversal of the $2,196,000 deferred tax asset valuation allowance established during 1995.
RESULTS OF OPERATIONS - YEARS ENDED DECEMBER 31, 1995 AND 1994
REVENUE. Revenue for 1995 was $40,476,000, a decrease of $3,911,000, or 9%, as compared to 1994. The following table reflects the Company's average oil and gas prices and its average daily oil and gas production for the years presented:
YEAR ENDED DECEMBER 31, ----------------------- 1996 1995 % CHANGE Average price: Oil (per bbl). . . $17.02 $15.63 9 Gas (per Mcf). . . $ 1.56 $1.69 (8)
Average daily production: Oil (Bbl). . . . . 3,160 3,501 (10) Gas (Mcf). . . . . 35,154 39,389 (11)
The declines in production are partially attributable to the sale of marginal properties during 1995. Lower production also resulted from normal depletion-related declines that were not fully offset by new drilling and recompletion activities. The Company recognized gas revenues for payments received with respect to transferred Section 29 tax credits, in the amounts of $2,857,000 and $2,123,000 for the years ended December 31, 1995 and 1994, respectively.
LEASE OPERATING EXPENSES. Lease operating expenses for 1995 were $8,196,000, a decrease of $446,000, or 5%, compared to 1994. Lease operating costs per Mcfe produced during 1995 averaged $.42 compared to $.39 in 1994. These higher costs per Mcfe were caused primarily by a decline in the number of new wells brought on line, since such wells typically have relatively high initial production rates, generating average unit production costs that are lower than more mature properties.
PRODUCTION TAXES. Production taxes for 1995 were $3,478,000, an increase of $46,000, or 1%, compared to 1994. Production taxes as a percent of oil and gas sales for 1995 were 8.8%, compared to 7.8% in 1994. The increased average tax rate was due to a greater portion of sales occurring in higher-tax jurisdictions in 1995.
DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and amortization expense for 1995 was $17,202,000, a decrease of $961,000, or 5%, as compared to 1994. The decrease was attributable to the lower production volumes in 1995 as compared to 1994, as the average depletion rate of $.84 per Mcfe produced in 1995 was higher than the $.77 per Mcfe rate in 1994. The increase reflects investment costs per Mcfe of reserves added during the second half of 1994 and in 1995 which were above the Company's historical average, as well as a reduction in estimated proved reserves at December 31, 1995 due, in part, to the effects of using lower gas prices in determining economic production limits.
PROPERTY IMPAIRMENT. During 1995, the Company recognized a property impairment charge of $26.5 million, as the result of the capitalized costs of its oil and gas properties exceeding a "ceiling" on such costs computed in accordance with prescribed accounting guidelines.
GENERAL AND ADMINISTRATIVE, NET. General and administrative expenses for 1995 were $5,498,000, an increase of $857,000, or 18%, as compared to 1994. The increase is primarily due to smaller recoveries from third-party working interest owners and nonrecurring charges of $545,000 related to staff reductions, settlement of a legal dispute, and an unsuccessful corporate acquisition effort. The lower recoveries resulted from the Company's acquisition in late-1994 of additional working interests in certain properties that it operates and reduced billings for drilling and completion overhead due to a less active property development program in 1995. Decreases in gross general and administrative expenses resulting from late-1995 reductions in office staff and other administrative costs had minimal impact in 1995.
INTEREST EXPENSE. Interest expense for 1996 totaled $6,432,000, an increase of $2,814,000, or 78%, as compared to 1994. This increase was due to the combined effects of increased average borrowings and higher interest rates, as summarized below:
YEAR ENDED DECEMBER 31, ---------------------- 1996 1995
Average borrowings (in thousands) $ 78,800 $ 55,600
Average interest rate on borrowings 7.3% 5.7%
INCOME TAX BENEFIT (PROVISION). The difference between the income tax benefit for 1995, and the amount that would be calculated by applying statutory income tax rates to the loss before income taxes is due to the establishment of a $2,196,000 deferred tax asset valuation allowance during 1995.
LIQUIDITY AND CAPITAL RESOURCES
In February 1996, the Company entered into two agreements pursuant to which it sold all of its assets in the D-J Basin, effective January 1, 1996, for an aggregate adjusted sales price of $123.5 million. The sale of approximately one-third of these D-J Basin assets was closed in March 1996 and the sale of the remainder was closed in June 1996. Combined, these transactions resulted in the disposition of two-thirds of the Company's total wells and approximately 70% of its estimated proved oil and gas reserves as of December 31, 1995. A portion of the sales proceeds was used to repay all outstanding long-term debt and the remainder, net of transaction costs, was initially invested in short-term, interest-bearing cash equivalents pending redeployment into new oil and gas investments. The Company's remaining producing properties after the sale were primarily mature oil and gas fields in the Powder River Basin, Green River Basin, and elsewhere in the Rocky Mountain region.
In August 1996, following the sale of the D-J Basin assets, the Company entered into an amended and restated credit agreement with its existing bank group that improved certain terms, including fees and interest rates, applicable under the line of credit. The amended credit agreement provides for the interest rate on borrowings to be determined by reference to either the prime rate or LIBOR, at the Company's election. A varying spread of 0% to 0.5% is added to the prime rate, or 0.625% to 1.25% is applied to LIBOR, based upon the Company's debt-to-capitalization ratio at the time. The credit agreement provides for borrowings to be revolving loans until August 1, 1999, at which time the outstanding balance will be converted into a four-year amortizing term loan. The credit agreement contains various covenants, including ones that could limit the Company's ability to incur other debt, dispose of assets, pay dividends, or repurchase stock. The borrowing base under the revolving credit facility was established at $25 million in August 1996 and is scheduled to be redetermined as of April 30, 1997 and generally thereafter at six month intervals until converted into a term loan. The Company is anticipating that at the next redetermination date the borrowing base will be established at a level at or above the present level of $25 million, but there can be no assurance that this will occur. As of December 31, 1996, there were no borrowings outstanding under the facility. In addition to availability under the credit line, the Company's capital resources at December 31, 1996 included approximately $19.2 million of net working capital, inclusive of $22 million of cash and cash equivalents.
Prior to sale of its D-J Basin assets the Company had a working capital deficit and little unutilized capacity under its revolving credit facility. The D-J Basin asset sales significantly improved the Company's liquidity but also significantly reduced its oil and gas production and, consequently, its operating cash flow. Prior to 1995 the Company's investments in oil and gas properties typically exceeded its cash flow from operating activities, with the excess funded primarily with bank borrowings and proceeds from equity offerings. The Company's total capital expenditures on oil and gas properties totaled $22.8 million in 1996, $15.7 million in 1995, and $66.5 million in 1994. By comparison, cash flows from operating activities before changes in operating assets and liabilities totaled $5.7 million in 1996, $17.1 million in 1995, and $25 million in 1994. The large decline in capital expenditures from 1994 to 1995 was due, in part, to liquidity constraints that developed when declining Rocky Mountain gas prices unfavorably impacted cash flow and borrowing capacity and reduced the number of economically viable development projects within the Company's asset base. The Company's capital expenditures are generally discretionary and activity levels are determined by a number of factors, including oil and gas prices, interest rates, availability of funds, quantity and character of identified investment projects, availability of service providers, and competition. The Company intends to use the improved liquidity resulting from the D-J Basin asset sales to make new investments in oil and gas properties, through acquisition and development of proved properties, exploration, and exploitation of its property base.
The Company had no extraordinary capital expenditure commitments pending at December 31, 1996. However, in February 1997 the Company acquired, for $14.4 million, interests in three Gulf of Mexico lease blocks with recently drilled wells that were attributed proved reserves but which required additional development to commence production. Development plans for these properties are discussed later in this section. Also, on March 5, 1997 the Company participated in winning bids for 11 tracts at the central Gulf of Mexico lease sale held by the federal government's Minerals Management Service (MMS). If all 11 tracts are awarded by the MMS, which can choose to reject all bids for a given lease, the Company's net share of the related leasehold bonuses will total approximately $5.7 million.
During the past several years the Company has been increasing its capital expenditures on exploration activities. Exploration activities generally have greater investment risk but a higher targeted rate of return than acquisition and development activities. The range of possible investment outcomes is ordinarily much greater for exploration than for other oil and gas investments. In 1996 the Company began focusing its exploration activities in the shallow waters of the Gulf of Mexico, offshore Louisiana and Texas. The Company had conducted no previous operations in the area and began the period with no prospect inventory. To conduct its Gulf Coast exploration activities the Company formed a Houston office staffed with experienced Gulf Coast geoscientists, engineers, and support personnel. During its initial year of operations in the Gulf Coast area the Company invested approximately $14.9 million in related exploration activities, including costs relating to leaseholds that were unproved at December 31, 1996 but net of $4.9 million of costs recouped through resale of partial interests in prospects to industry partners. Such investments primarily related to acquisitions of seismic data and mineral leaseholds, and participation in drilling four exploratory wells, two of which were successful. Because the successful wells were drilled late in the year, the Company did not incur significant related development costs in 1996. The Company's exploration plans for 1997 anticipate participation in five to ten new exploratory test wells, but only one such well has yet been scheduled and the actual number of test wells drilled may be more or less than anticipated.
The two successful wells noted above were drilled on Eugene Island (EI) Blocks 64 and 65, respectively. Both wells were attributed proved reserves as of December 31, 1996 but were categorized as undeveloped at that date because substantial future operations were required in order to make the wells capable of production. The EI 64 #1 well is expected to commence production in the second quarter of 1997 after completion and tie-in to a nearby production platform owned and operated by a third party. It is expected that a production platform will be installed on the EI 65 property in the third quarter of 1997 to produce the #1 well and, if it is successful, the #2 well which is currently drilling.
Through the $14.4 million acquisition consummated in February 1997, the Company increased its interests in EI Blocks 64 and 65. The third property acquired was an interest in East Cameron (EC) Block 378. A well on EC 378 was completed subsea in January 1997 and is waiting on pipeline installation to connect to a nearby third party production platform. Initial production from EC 378 is expected to commence during the third or fourth quarter of 1997.
The Company's capital budget for calendar 1997, excluding acquisitions not already consummated, is approximately $55 million, allocated as follows: approximately $15 million is provided for acquisitions of proved properties; approximately $20 million is provided for acquisitions of prospect leaseholds, seismic data procurement, and exploratory drilling costs; approximately $15 million relates to anticipated development of the Company's existing property base, including EI 64, EI 65, EC 378, and the Company's Rocky Mountain assets; and approximately $5 million is provided for other activities, including current year development of assumed exploratory discoveries. Much of this budget is dependent on future developments that are not entirely within the Company's control and which may not occur. The Company's actual capital expenditures may vary significantly from these estimates. Further, the Company intends to continue to pursue acquisitions of proved properties, primarily in the Gulf Coast and Rocky Mountain regions, which, while not budgeted, could be very significant.
Management believes that the current-year budget, as described above, can be funded without new sources of capital, by utilizing net working capital at the beginning of the period, projected cash flow, and borrowings under the revolving credit facility with the Company's bank group. Cash flow is expected to increase significantly during the latter part of the year when EI 64 and 65 and EC 378 are projected to be on-line; however, these properties have not produced before and the forecast on-line dates and production rates may not be achieved. If conditions warrant, the Company may consider raising additional capital through issuance of debt or equity securities. Should the Company undertake a large acquisition, issuing such securities or monetizing assets would likely be required to fund the transaction. In the absence of additional liquidity, the Company's ability to fund investment activities in future periods will be significantly affected by the results obtained from investments made in 1997.
Changes In Prices
The Company's revenue, cash flow, and the value of its oil and gas properties have been, and will continue to be, affected by changes in oil and natural gas prices. The Company's ability to maintain current borrowing capacity and to obtain additional capital on attractive terms is also substantially dependent on oil and natural gas prices. As such, changes in oil and gas prices can significantly affect the amount of the Company's capital expenditures. Oil and natural gas prices are subject to significant seasonal and other fluctuations that are beyond the Company's ability to control or predict. The Company periodically enters into product swap agreements in order to hedge against the volatility of product prices. Although the Company enters into the agreements to limit exposure to price decreases, the agreements also limit the Company's ability to benefit from significant price increases on the contract volumes. Effective July 1, 1996, the Company entered into a crude oil swap agreement with a contract volume of 10,000 barrels per month through December 31, 1997. This agreement provides for the cash settlement of the differential between the $18.32 per barrel contract price and the average closing NYMEX crude oil price during each month. The Company has also entered into a crude oil collar arrangement effective for calendar 1997 on an additional 10,000 barrels per month. This agreement provides for the cash settlement of the differential between the monthly average closing NYMEX price and the contract floor of $19.50 per barrel or the contract ceiling of $24.35 per barrel, if the average monthly NYMEX price falls outside of the range defined by such contract floor and contract ceiling. Any gain or loss realized on these agreements is included as a component of oil sales in the month of production.
CERTAIN FACTORS THAT MAY AFFECT FUTURE RESULTS
Statements that are not historical facts contained in this report are forward-looking statements that involve risks and uncertainties that could cause actual results to differ from projected results. Such statements address activities, events or developments that the Company expects, believes, projects, intends or anticipates will or may occur, including such matters as future capital, development and exploration expenditures (including the amount and nature thereof), drilling of wells, reserve estimates (including estimates of future net revenues associated with such reserves and the present value of such future net revenues), future production of oil and gas, business strategies, expansion and growth of the Company's operations, cash flow and anticipated liquidity, prospect development and property acquisition, obtaining financial or industry partners for prospect or program development, or marketing of oil and gas. Factors that could cause actual results to differ materially ("Cautionary Disclosures") are described, among other places, in the Marketing, Competition, and Regulation sections in this Form 10-K and under the caption "Management's Discussion and Analysis of Financial Condition and Results of Operations." Without limiting the Cautionary Disclosures so described, Cautionary Disclosures include, among others: general economic conditions, the market price of oil and natural gas, the risks associated with exploration, the Company's ability to find, acquire, market, develop and produce new properties, operating hazards attendant to the oil and natural gas business, the Company's inexperience in the Gulf of Mexico, uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures, the strength and financial resources of the Company's competitors, the Company's ability to find and retain skilled personnel, climatic conditions, labor relations, availability and cost of material and equipment, delays in anticipated start-up dates, environmental risks, the results of financing efforts, and regulatory developments. All written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by the Cautionary Disclosures, including without limitation those contained in the President's letter contained in the Annual Report to Stockholders. The Company disclaims any obligation to update or revise any forward- looking statement to reflect events or circumstances occurring hereafter or to reflect the occurrence of anticipated or unanticipated events.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The Consolidated Financial Statements that constitute Item 8 are attached at the end of this report. An index to the Consolidated Financial Statements appears in Item 14(a) of this report.
ITEM 9.
ITEM 9. CHANGES 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 incorporated by reference from the sections entitled "Management" and "Disclosure of Filings by Insiders" 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, which are 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.
CERTAIN DEFINITIONS
The terms defined in this section are used throughout this report.
Acreage held by production. Acreage covered by an oil and gas lease which has a producing well on it, or which is pooled with a lease or leases having one or more producing wells on them, so the lease is maintained in effect for the duration of such production.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
Bcf. Billion cubic feet (of gas).
Bcfe. Billion cubic feet (of gas) equivalent.
Behind-pipe reserves. Proved reserves in a formation in which production casing has already been set in the wellbore, but from which production has not commenced.
Btu. British thermal unit.
Commingle. The combining of production from more than one zone in the same well to produce from multiple zones at the same time.
Development location. A location on which a development well can be drilled.
Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive in an attempt to recover proved undeveloped reserves.
Drilling locations. A site on which a well can be drilled consistent with local spacing rules for the purpose of recovering possible, probable or proved reserves.
Dry well. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
Exploitation. The conduct of a drilling or recompletion operation intended to recover reserves from a formation known to be productive in the area or on trend with existing production but not classifiable as proved.
Exploratory well. A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir.
Farmout. An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location.
Gross acres. An acre in which a working interest is owned.
Gross well. A well in which a working interest is owned.
MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.
MBtu. One thousand Btus.
Mcf. One thousand cubic feet (of gas).
Mcfe. One thousand cubic feet of natural gas equivalent. In reference to crude oil or other liquid hydrocarbons, equivalents are determined using the ratio of one Bbl of crude oil or other liquid hydrocarbon to 6 Mcf of gas.
MMBbl. One million barrels of crude oil or other liquid hydrocarbons.
MMBtu. One million Btus.
MMcf. One million cubic feet.
MMcfe. One million cubic feet (of gas) equivalent.
Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells.
Overriding royalty interest. An interest in an oil and gas property entitling the owner to a share of oil and gas production free of costs of production.
Present value of future net revenues. Estimated future net revenues discounted at a rate of ten percent per annum.
Productive well. A well that is producing oil or gas or that is capable of production.
Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved undeveloped location. A site on which a development well can be drilled consistent with local spacing rules for the purpose of recovering proved reserves.
Proved undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Recompletion. The completion for production of an existing wellbore in another formation from that in which the well has previously been completed.
Undeveloped acreage. Lease acreage 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 such acreage contains proved reserves.
Working interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules
PAGE
Report of Independent Public Accountants . . . . . . . . . . . . .
Consolidated Statements of Operations for the years ended December 31, 1996, 1995, and 1994 . . . . . . . . . . . . . .
Consolidated Balance Sheets as of December 31, 1996 and 1995 . . .
Consolidated Statements of Cash Flow for the years ended December 31, 1996, 1995 and 1994. . . . . . . . . . . .
Consolidated Statements of Changes in Stockholders' Equity for the years ended December 31, 1996, 1995 and 1994. . . . .
Notes to Consolidated Financial Statements . . . . . . . . . . . .
All other schedules are omitted because the required information is not applicable or is not present in amounts sufficient to require submission of the schedule or because the information required is included in the Combined Financial Statements and Notes thereto.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders and Board of Directors of Basin Exploration, Inc.:
We have audited the accompanying consolidated balance sheets of Basin Exploration, Inc., and subsidiaries, as of December 31, 1996 and 1995, and the related consolidated statements of operations, changes in stockholders' equity and cash flow for each of the three years in the period ended December 31, 1996. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated finan- cial 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 consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Basin Exploration, 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.
/s/ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP
Denver, Colorado, February 14, 1997.
BASIN EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS
BASIN EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
BASIN EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS--(Continued)
BASIN EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOW
BASIN EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOW--(CONTINUED)
BASIN EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
BASIN EXPLORATION, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES ------------------------------------------
Organization and Operations -- The consolidated financial --------------------------- statements include the financial statements of Basin Exploration, Inc. and its wholly owned subsidiaries,(collectively referred to as "Basin" or the "Company"). Basin, as operator of jointly owned oil and gas properties, sells a significant amount of such production to certain major customers (see Note 9), and pays vendors for oil and gas services. Joint interest receivables are subject to collection under terms of operating agreements which generally provide lien rights.
The accompanying financial statements present the operations of the Company on a consolidated basis. All significant intercompany accounts and transactions have been eliminated in consolidation. 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.
Certain reclassifications have been made to amounts reported in previous years to conform to 1996 presentation.
Cash Equivalents -- Cash equivalents are comprised of highly ---------------- liquid instruments with original maturities of three months or less. The total carrying amount of cash and equivalents approximates the fair value of such instruments.
Oil and Gas Properties -- The Company follows the full cost ---------------------- method of accounting for oil and gas properties. Under this method, all costs associated with the development, exploration and acquisition of oil and gas properties are capitalized in the Company's one cost center (full cost pool), which is the continental United States including the Gulf of Mexico. Payroll and other internal costs capitalized include salaries and related fringe benefits paid to employees directly engaged in the acquisition, exploration and development of oil and gas properties as well as all other directly identifiable, internal costs associated with these activities. Payroll and other internal costs associated with production operations and general corporate activities are expensed in the period incurred. Future development, site restoration, dismantlement and abandonment costs, net of salvage values, are estimated on a property-by- property basis based on prevailing prices and are amortized to expense, along with the capitalized costs discussed above, using the unit-of-production method based upon actual production and estimates of proved reserve quantities. Accumulated depreciation, depletion and amortization is recorded on the balance sheet as a reduction to property, plant and equipment costs. Proceeds from sales of oil and gas properties are credited to the full cost pool with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas.
If capitalized costs, net of amortization and related deferred taxes, exceed the full cost ceiling, the excess would be expensed in the period such excess occurs. The full cost ceiling includes an estimate of the discounted value of future net revenues attributable to proven reserves, using various assumptions and parameters consistent with promulgations of the Securities and Exchange Commission. The full cost ceiling may be particularly sensitive to changes in prevailing oil and gas sales prices or forecast production rates. The Company recognized $26,500,000 of such impairment at September 30, 1995.
The Company invests in unevaluated oil and gas properties and related assets for the purpose of future exploration for proved reserves. The costs of such assets are included in unproved oil and gas properties at the lower of cost or estimated fair market value.
Inventory -- Inventory of lease and well equipment is stated --------- at the lower of cost or market determined using the specific identification method.
Furniture and Equipment -- Furniture and equipment is ----------------------- depreciated over estimated useful lives of five to seven years. Maintenance and repair costs are expensed as incurred.
BASIN EXPLORATION, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Income Taxes -- The Company computes income taxes in ------------ accordance with Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes." SFAS 109 requires an asset and liability approach which results in the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between the carrying amounts and the tax bases of those assets and liabilities. SFAS 109 also requires the recording of a valuation allowance if it is more likely than not that some portion or all of a deferred tax asset will not be realized.
Hedging Activities -- The Company periodically enters into ------------------ agreements with third parties to hedge against the effects of fluctuations in future oil and gas prices. Gains or losses on such agreements are deferred and recognized as oil and gas revenue when the hedged production occurs.
At December 31, 1996, the Company was a party to a crude oil swap agreement and a crude oil collar arrangement, each with a contract volume of 10,000 barrels per month through December 31, 1997. The swap agreement provides for the cash settlement of the differential between the $18.32 per barrel contract price and the average closing NYMEX crude oil price during each month. The collar arrangement provides for the cash settlement of the differential between the monthly average closing NYMEX price and the contract floor of $19.50 per barrel or the contract ceiling of $24.35 per barrel, if the monthly average closing NYMEX price falls outside of the range defined by such contract floor and contract ceiling. In accordance with SFAS 107, "Disclosures About Fair Value of Financial Instruments," the Company has estimated the fair value of its hedging arrangements utilizing the NYMEX crude oil strip at December 31, 1996. While it is not the Company's intention to terminate either of the arrangements, it is estimated that the Company would have been required to pay approximately $525,000 to terminate the arrangements on December 31, 1996. As of February 12, 1997, the estimated cost to terminate such arrangements was approximately $325,000, inclusive of the actual cost of contract settlements through that date. Due to the volatility of crude oil prices, the fair market value may not be representative of the actual gain or loss that will be realized by the Company in 1997.
The Company recognized a reduction in oil revenue of $480,000, $115,000 and $95,000 under hedging agreements in 1996, 1995 and 1994, respectively. The Company recognized a reduction in gas revenue of $206,000 under hedging agreements in 1994.
Earnings (Loss) Per Share -- Earnings (loss) per share have ------------------------- been computed based on the weighted average number of common shares outstanding. The impact of dilutive common stock equivalents on earnings (loss) per share was immaterial.
(2) RESTRICTED CASH ---------------
Well Plugging -- The Company was required under a certain ------------- farmout agreement to deposit in an escrow account amounts for future plugging and abandonment costs beyond a one-year time period. The total cash held in escrow at December 31, 1995, was $578,000. Such escrow account was closed and the funds were released to the Company in November 1996.
(3) ACQUISITIONS AND DIVESTITURES OF OIL AND GAS PROPERTIES -------------------------------------------------------
In February 1996, the Company entered into agreements pursuant to which it sold all of its assets in the D-J Basin in two transactions closed in March and June 1996, for an aggregate sales price of $123,500,000, effective January 1, 1996. Combined, these transactions resulted in Basin selling its interests in approximately two-thirds of its producing wells and 70% of its proved oil and gas reserves at December 31, 1995. Because the second transaction constituted the sale of a significant portion of the Company's total oil and gas reserves which would significantly alter the relationship between the Company's capitalized costs and its proved reserves, net capitalized costs of oil and gas properties were allocated between the reserves sold and retained based upon their estimated relative reserve quantities as of June 7, 1996 and a resulting gain of approximately $22,500,000 was recognized. A portion of the proceeds from the sales was used to payoff all outstanding bank debt and residual proceeds, net of transaction costs, were invested in short-term interest bearing cash equivalents. Revenue and expenses associated with the sold properties were included in the Company's results of operations through the respective closing dates.
BASIN EXPLORATION, INC AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
In November 1994 the Company acquired all of the outstanding stock of Sterling Energy Corp. ("Sterling") for aggregate consideration of approximately $15.4 million consisting of approximately $10.1 million in cash, the assumption of $3.6 million of net liabilities, warrants to purchase 300,000 shares of the Company's common stock at an exercise price of $14.00 valued at $1.5 million, and $.2 million in transaction expenses. The acquisition included producing and non-producing oil and gas properties and undeveloped acreage located in the Scott and Draw fields in Converse County, Wyoming and in the Tohonadla field in San Juan County, Utah, as well as a gas processing plant located in Wyoming. The acquisition was funded partially with an increased revolving credit facility. The Company accounted for the Sterling acquisition using purchase accounting and began consolidating the results as of the December 1994 close date.
(4) LONG-TERM DEBT --------------
On August 6, 1996, the Company entered into an Amended and Restated Credit Agreement with its existing bank group. The initial borrowing base was set at $25,000,000 and is scheduled to be determined as of April 30, 1997 for the following six month period. The Credit Agreement provides for the interest rate on borrowings to be determined based on the prime rate or LIBOR, at the Company's election. A varying spread above the prime rate ranging from 0% to 0.5% and over LIBOR ranging from 0.625% to 1.25% will be applied based upon the Company's applicable debt- to-capitalization ratio. The Credit Agreement provides for borrowings to be revolving loans until August 1, 1999, at which time the outstanding balance is scheduled to convert to a four year amortizing term loan. The Credit Agreement contains various covenants, including ones that could limit the Company's ability to incur other debt, dispose of assets, pay dividends or repurchase stock. The note may be secured by the Company's oil and gas properties in certain circumstances, at the election of the lending banks. There were no borrowings outstanding under the facility at December 31, 1996.
Effective May 31, 1995, in order to improve management of interest rate risk, Basin entered into an interest rate swap agreement. Under the agreement, the Company fixed the LIBOR reference rate on a notional amount of $50 million at 6 percent per annum through May 31, 1996.
Debt is payable as follows:
(5) BENEFIT PLANS -------------
401(k) Savings -- The Company has a 401(k) profit sharing -------------- plan (the "Plan"). Eligible employees may make voluntary contributions to the Plan, which may be matched by the Company, at its discretion, up to 6 percent of the employee's eligible compensation. The Company has historically matched the first three percent of employees' eligible compensation that is contributed under the Plan. The amount of employee contributions is limited as specified in the Plan. The Company may, at its discretion, make additional contributions to the Plan. The Company expensed $96,000, $195,000, and $261,000, with respect to the Plan for the years ended December 31, 1996, 1995 and 1994, respectively.
BASIN EXPLORATION, INC AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Stock Plan -- Under the Company's Employees' Equity ---------- Incentive Plan and Non-Employee Directors' Stock Option Plan, officers, key employees, consultants and directors of the Company are eligible to receive incentive stock options, non-qualified stock options and restricted stock. At December 31, 1996, a total of approximately 1,365,000 shares were available for grant under the plans. Shares granted generally vest over three to four years, and expire after ten years. A total of 684,000 shares of the Company's common stock are subject to such plans as of December 31, 1996, including 35,000 unvested shares of restricted stock and 649,000 outstanding stock options.
The following table summarizes the changes in stock options:
At December 31, 1996, the weighted average exercise price and weighted average remaining life for options outstanding was $6.55 per share and 8.3 years, respectively. Additional information regarding the outstanding options at December 31, 1996, is as follows.
In connection with its initial public offering ("IPO") in 1992, the Company granted options to two officers to purchase 100,000 shares each of the Company's common stock at a price substantially below the IPO price of $9.50 per share. The Company recognized compensation expense related to these options of approximately $97,000 and $233,000 for the years ended December 31, 1995 and 1994, respectively.
The Company granted 25,000, 32,000, and 25,000 shares of restricted stock during 1996, 1995 and 1994, respectively. Related compensation expense was recognized in the amounts of approximately $98,000, $205,000, and $121,000 for the years ended December 31, 1996, 1995, and 1994, respectively. Cumulatively through December 31, 1996, 35,000 shares of restricted stock remained subject to forfeiture, 48,000 shares of restricted stock had been forfeited and 42,000 shares were no longer subject to restriction.
In connection with the Sterling acquisition, the Company issued warrants to purchase 300,000 shares of the Company's common stock at an exercise price of $14.00 per share. Such warrants became exercisable on October 13, 1994 and have an expiration date of December 31, 1999.
In October 1995, the Financial Accounting Standards Board issued SFAS 123, "Accounting for Stock-Based Compensation." SFAS 123 was effective for 1996 and recommends a fair value based method of accounting for employee stock compensation, including stock options. However, companies may choose to account for stock compensation using the intrinsic value based method as prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" and provide pro forma disclosures of net income and earnings per share as if the fair value based method had been applied. The Company has elected to continue to account for stock compensation using the intrinsic value based method.
BASIN EXPLORATION, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS --(CONTINUED)
Had the Company elected to follow SFAS 123, the fair value of each option grant would have been estimated on the date of grant using the Black-Sholes option-pricing model with the following weighted-average assumptions used for grants in 1996 and 1995: risk free interest rate of 6.75%; expected dividend yield of 0%; expected life of 5 years; and expected volatility of 55%. Based upon these assumptions, the weighted average fair value of options granted during 1996 and 1995 was $2.73 and $2.96 per share, respectively. SFAS 123 would have had no significant impact on reported operating results for the years ended December 31, 1996 and 1995.
(6) COMMITMENTS AND CONTINGENCIES -----------------------------
Leases -- The Company is the primary obligor under various ------ noncancelable office space operating lease arrangements. The Company also subleases certain office space to and from third parties under various noncancellable lease arrangements. The following is a schedule of future minimum lease payments under these leases:
Payments related to these leases obligations were approximately $707,000, $710,000, and $435,000 for the years ended December 31, 1996, 1995 and 1994, respectively.
Legal Proceedings -- The Company, from time to time, is ----------------- involved in various legal and administrative proceedings and claims of various types which arise in the ordinary course of its business. While any litigation contains an element of uncertainty, in the opinion of management, none of these actions, either individually or in the aggregate will have a material adverse effect on results the Company's financial condition, liquidity or results of operations.
(7) INCOME TAXES ------------
The components of the provision (benefit) for income taxes are as follows:
BASIN EXPLORATION, INC AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
Reconciliations of income tax provisions (benefit) computed at the federal statutory rate with income tax provisions recorded by the Company for each of the past three years are as follows:
The tax effects of significant temporary differences representing deferred tax assets and liabilities are as follows:
As of December 31, 1996, the Company has alternative minimum tax credit carry forwards for income tax purposes of approximately $1,475,000 which may be utilized to reduce future tax liability of the Company. These carry forwards have no expiration date.
(8) RELATED PARTY TRANSACTIONS --------------------------
Prior to the IPO, the Company advanced $559,000 to its principal stockholder at an annual interest rate of 9 percent. The note was amended in 1996 and the balance is now due in December 1997 with interest only payments due quarterly.
BASIN EXPLORATION, INC AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
(9) OIL AND GAS ACTIVITIES ----------------------
The Company's oil and gas operations are conducted in the United States. Certain information concerning these activities follows:
Major Purchasers -- The following parties purchased ten ---------------- percent or more of the Company's oil and gas production.
Purchaser Year ended December 31, 1996 1995 1994 -------------------------------------------------------
PanEnergy 43% 62% 77% Eighty-Eight Oil Company 26% 16% (a)
(a) less than ten percent
Section 29 Tax Credits -- The Company received $1.5 million ---------------------- and $3 million in 1995 and 1994 respectively, for Section 29 tax credits associated with gas production from various oil and gas properties of the Company. Such proceeds were recorded as unearned income and recognized as incremental gas revenues as the gas was produced and the credits earned. The Company recognized approximately $2,857,000 and $2,123,000 of additional gas revenue during the years ended December 31, 1995 and 1994, respectively, related to the amortization of this unearned income.
Costs Incurred -- Costs incurred in oil and gas operations -------------- and related depreciation, depletion and amortization per equivalent unit-of-production are as follows:
Year Ended December 31, 1996 1995 1994 - ---------------------------------------------------------------------- (in thousands)
Property acquisition- Unproved $ 5,056/1/ $ 2,429 $ 5,275 Proved 3,067 3,889 16,751 Exploration costs 10,250 2,003 2,361 Development costs 4,472 7,427 42,113 - ---------------------------------------------------------------------- Gross expenditures $ 22,845 $ 15,748 $ 66,500 ======================================================================
Depletion per one thousand cubic feet of gas equivalent $ 0.82 $ 0.84 $ 0.77 ======================================================================
/1/ Excludes $4,914,000 of costs recouped through the resale of partial interests in prospects to industry partners.
Costs Not Being Amortized -- Oil and gas property costs not ------------------------- being amortized at December 31, 1996, consisted of $9,822,000 of leasehold and seismic costs, of which $9,058,000, $488,000 and $276,000 were incurred in 1996, 1995 and 1994, respectively. The Company anticipates that substantially all unevaluated costs will be classified as evaluated costs within the next three years.
BASIN EXPLORATION, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION - ------------------------------------------------------
The determination of oil and gas reserves is complex and highly interpretive. Assumptions used to estimate reserve information may significantly increase or decrease such reserves in future periods. The estimates of reserves are subject to continuing changes and, therefore, an accurate determination of reserves may not be possible for many years because of the time needed for development, drilling, testing and studies of the reservoirs. The following unaudited table, based upon estimates of onshore reserves prepared by the Company's engineers and audited by Netherland, Sewell & Associates, Inc. at December 31, 1996, 1995 and 1994 and estimates of offshore reserves prepared by Ryder Scott Company Petroleum Engineers at December 31, 1996, sets forth the estimated quantities of proved oil and gas reserves for the Company and the changes in total proved reserves as of December 31, 1996, 1995, and 1994. All such reserves are located in the United States.
ANALYSES OF CHANGES IN PROVED RESERVES - --------------------------------------
STANDARDIZED MEASURE - --------------------
The unaudited standardized measure of discounted future net cash flows related to proved oil and gas reserves are as follows:
December 31, 1996 1995 1994 - ---------------------------------------------------------------------- (in thousands)
Future production revenues $ 289,105 $ 439,415 $ 505,636 Future production costs (108,522) (155,087) (163,244) Future development costs (20,583) (45,907) (49,293) Future income taxes (39,101) (25,644) (45,252) - ---------------------------------------------------------------------- Future net cash flows 120,899 212,777 247,847 Discount (57,593) (95,529) (106,495) - ---------------------------------------------------------------------- Standardized measure of discounted future net cash flows/1/ $ 63,306 $ 117,248 $ 141,352 ======================================================================
/1/ Total future net cash flows before income taxes discounted at 10% per annum are $83,656,000, $129,068,000 and $162,858,000 as of December 31, 1996, 1995 and 1994, respectively.
BASIN EXPLORATION, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS --(CONTINUED)
The estimate of future income taxes is based on the future net cash flows from proved reserves adjusted for the tax basis of the oil and gas properties but without consideration of general and administrative and interest expenses. For standardized measure purposes the Company estimates future income taxes using the "year-by- year" method. For ceiling test purposes the Company estimates future income taxes using the "short-cut" method.
A summary of changes in the standardized measure of discounted future net cash flows is as follows:
There are numerous uncertainties inherent in estimating quantities of proved reserves and projected future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data and standardized measures set forth herein represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including geologic success, prices, future production levels and costs, that may not prove correct over time. Predictions of future production levels are subject to great uncertainty, and the meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Oil and gas prices have fluctuated widely in recent years. The calculated weighted average sales prices utilized for the purposes of estimating the Company's proved reserves and future net revenue were and $25.35 per barrel of oil and $3.02 per Mcf of gas at December 31, 1996, $18.64 per barrel of oil and $1.56 per Mcf of gas at December 31, 1995 and $16.44 per barrel of oil and $1.63 per Mcf of gas at December 31, 1994.
BASIN EXPLORATION, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS --(CONTINUED)
UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA - ----------------------------------------------- (in thousands except per share amounts)(unaudited)
(a)(3) Exhibits
EXHIBIT NUMBER DESCRIPTION OF EXHIBITS ------- -----------------------
2.1 -- Agreement and Plan of Merger between Sterling Energy Corporation, Basin Energy, Inc. and Basin Exploration, Inc. dated October 13, 1994/7/ 2.2 -- Plan of Merger between Basin Sterling, Inc. and Basin Exploration, Inc. dated November 22, 1994/8/ 2.3 -- Plan of Merger between Basin Operating Company and Basin Exploration, Inc. dated December 14, 1994/8/ 3.1 -- Restated Certificate of Incorporation of Basin./2/ 3.2 -- Restated Bylaws of Basin./2/ 4.1 -- Common Stock Certificate of Basin./2/ 10.1 -- Equity Incentive Plan as amended June 6, 1996./1/ 10.2 -- Directors' Stock Option Plan as amended June 6, 1996./1/ 10.3 -- Key Employee Participation Plan./2/ 10.4 -- Employment Agreement dated March 31, 1992 by and between Basin and Michael S. Smith./3/ 10.5 -- Gulf Coast Geoscientist Overriding Royalty Interest Plan dated November 30, 1995./10/ 10.6 -- Form of Rights Agreement dated as of February 24, 1996, between Basin Exploration, Inc. and Corporate Stock Transfer, Inc. as Rights Agent./9/ 10.7 -- Performance Shares Plan approved February 4, 1997./1/ 10.8 -- Change of Control Employment Agreement dated October 13, 1995 between Basin Exploration, Inc. and Howard L. Boigon./10/ 10.9 -- Employment Agreement dated August 28, 1995 between Basin Exploration, Inc. and Samuel D. Winegrad./10/ 10.10 -- Employment Agreement dated June 28, 1995 between Basin Exploration, Inc. and Neil L. Stenbuck./10/ 10.11 -- Employment Agreement dated November 10, 1995 between Basin Exploration, Inc. and David A. Pustka./10/ 10.12 -- Employment Agreement dated February 23, 1996 between Basin Exploration, Inc. and Thomas J. Corley./1/ 10.13 -- Assignment and Assumption of Lease dated December 18, 1995 by and between Team, Inc., as original Tenant, Basin Exploration, Inc., as New Tenant, and FC Tower Property Partners, L.P., as Landlord./9/ 10.14 -- First Supplement to Amended Mortgage, Security Agreement, Assignment, Financing Statement and Fixture Filing dated May 8, 1995 by and between Basin Exploration, Inc. and Basin Gas Ltd. to NationsBank of Texas, N.A., as successor collateral agent for the benefit of Colorado National Bank, Union Bank and NationsBank of Texas, N.A./8/ 10.15 -- Second Supplement to Amended Mortgage, Security Agreement, Assignment, Financing Statement and Fixture Filing dated May 8, 1995 by and between Basin Exploration, Inc., and Basin Gas Ltd. to NationsBank of Texas, N.A. in its capacity as the successor collateral agent for the benefit of Colorado National Bank, Union Bank and NationsBank of Texas, N.A./10/ 10.16 -- Agreement for Purchase and Sale of Assets (Monetization) dated February 24, 1996 by and between Basin Exploration, Inc., HS Resources, Inc. and Orion Acquisition, Inc./7/ 10.17 -- Agreement for Purchase and Sale of Assets (Wattenberg), dated February 24, 1996 by and between Basin Exploration, Inc., HS Resources, Inc. and Orion Acquisition, Inc./7/ 10.18 -- Lease of Office Space dated September 25, 1992, between Brookfield Republic Inc. and Basin Operating Company, as amended/4/* 10.19 -- First Lease of Additional Office Space dated as of December 1, 1994, between Brookfield Republic, Inc. and Basin Operating Company./6/* 10.20 -- Amended and Restated Credit Agreement dated August 6, 1996 between the Company and Colorado National Bank, Union Bank of California, N.A. and NationsBank of Texas, N.A./11/ 10.21 -- Purchase and Sale Agreement dated February 13, 1997, between Hall-Houston Oil Company et al as Sellers and Basin Exploration, Inc. as Buyer./1/** 21 -- Subsidiaries./1/ 23.1 -- Consent of Arthur Andersen LLP/1/ 23.2 -- Consent of Netherland, Sewell & Associates, Inc./1/ 23.3 -- Consent of Ryder Scott Company/1/ 27 -- Financial Data Schedule./1/
- ----------------
/1/ Filed herewith.
/2/ Filed as an Exhibit to Basin's Registration Statement on Form S-1 as filed on March 17, 1992, Registration No. 33-46486, and incorporated herein by reference.
/3/ Filed as an Exhibit to Amendment No. 1 to Basin's Registration Statement on Form S-1 as filed on April 21, 1992, Registration No. 33-46486, and incorporated herein by reference.
/4/ Filed as an Exhibit to Basin's Registration Statement on Form S-1 as filed on October 25, 1993, Registration No. 33-70802, and incorporated herein by reference.
/5/ Filed as an Exhibit to Form 8-K filed on December 10, 1994, and incorporated herein by reference.
/6/ Filed as an Exhibit to Form 10-K/A-1 filed on June 26, 1995 and incorporated herein by reference.
/7/ Filed as an Exhibit to Form 8-K filed on March 6, 1996, and incorporated herein by reference.
/8/ Filed as an Exhibit to Form 10-K filed on March 28, 1995, and incorporated herein by reference.
/9/ Filed as an Exhibit to Form 8-K filed on February 26, 1996, and incorporated herein by reference.
/10/ Filed as an Exhibit to Form 10-K filed on March 28, 1996, and incorporated herein by reference.
/11/ Filed as an Exhibit to Form 10-Q filed on August 14, 1996, and incorporated herein by reference.
* Confidential treatment has been granted for portions of these Exhibits.
** Confidential treatment has been requested for portions of this Exhibit.
(b) Reports on Form 8-K
None
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.
BASIN EXPLORATION, INC.
By: /s/ MICHAEL S. SMITH Date: March 17, 1997 ------------------------------------- Michael S. Smith President, Chief Executive Officer and Chairman of the Board
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.
EXHIBIT INDEX
EXHIBIT NUMBER DESCRIPTION OF EXHIBITS PAGE NO. - ------- ----------------------- --------
10.1 -- Equity Incentive Plan as amended June 6, 1996. 71
10.2 -- Directors' Stock Option Plan as amended June 6, 1996. 90
10.7 -- Performance Shares Plan approved February 4, 1997. 98
10.12 -- Employment Agreement dated February 23, 1996 between Basin Exploration, Inc. and Thomas J. Corley. 107
10.21 -- Purchase and Sale Agreement dated February 13, 1997, between Hall-Houston Oil Company et al as Sellers and Basin Exploration, Inc. as Buyer. 118
21 -- Subsidiaries 157
23.1 -- Consent of Arthur Andersen LLP 158
23.2 -- Consent of Netherland, Sewell & Associates, Inc. 159
23.3 -- Consent of Ryder Scott Company 160
27 -- Financial Data Schedule 161