ITEM 1. BUSINESS.
General
Basin is an independent oil and gas company engaged in the exploration, development and acquisition of oil and gas properties located in the shallow waters of the Gulf of Mexico and selected areas of the onshore United States, including the Gulf Coast and the Powder River and Green River Basins of Wyoming. In 1996, we sold a significant portion of our developed properties in the Rocky Mountain region in order to commence an active exploratory drilling program in the Gulf of Mexico. Since that time, we have increased our proved reserves, production and operating cash flow primarily through our Gulf of Mexico operations. As of December 31, 1999, our proved reserves totaled approximately 210 Bcfe. Approximately 64% of our estimated proved reserves at December 31, 1999 are gas and 64% are located in the Gulf of Mexico.
Through December 1999, we have participated in the drilling of 52 wells in the Gulf of Mexico, 35 of which have found apparent commercial hydrocarbons, yielding a 67% success rate. We have owned an average working interest of 53% in these 52 wells and have operated 38, or 73%, of them. During 1999, we participated in drilling 21 wells in the Gulf of Mexico, including 17 exploratory wells and four development wells. Fifteen of these, or 71%, found apparent commercial hydrocarbons, including 11 of the exploratory wells and all four development wells. We also participated in five onshore exploratory wells in 1999, including one discovery and one well that was testing at year-end in the Green River Basin.
The majority of our proved reserves in the Gulf of Mexico are attributable to Miocene-age sands, within an area known as the Miocene trend. The Miocene trend is a prolific oil and gas producing area characterized by subtle hydrocarbon indicators, which are more readily detectable using 3-D seismic data that has become available since the mid-1990s. This trend is primarily located in water depths of less than 150 feet, near existing infrastructure.
Basin's onshore activities include exploring and developing oil and gas properties in southern Louisiana and Texas and in several areas in the Rocky Mountain region, including the Powder River and Green River Basins of Wyoming. Although the shallow waters of the Gulf of Mexico will remain our primary area of exploratory focus in 2000, we believe that the longer reserve life and exposure to more diverse opportunities offered by operations in onshore provinces will complement our offshore efforts. During 1999, we enhanced our onshore capabilities through the addition of experienced personnel and acquisitions of geophysical data. Our onshore properties accounted for 11% of our production and approximately 14% of our capital investments during 1999.
Our average daily net oil and gas production in 1999 was 89 MMcfe, representing a 48% increase over our 1998 average daily net production of 60 MMcfe. Approximately 84% of our total production in 1999 was natural gas. Our 1999 revenues and cash flow from operations before working capital changes increased from 1998 levels by 47% and 57%, to approximately $72 million and $53 million, respectively. Our average realized prices were approximately the same in 1998 and 1999 on an energy equivalent basis, net of hedging affects. For 1999, our revenue per Mcfe of production averaged $2.20 and our cash flow from operations per Mcfe equaled $1.62.
The increase in our production from 1998 to 1999 was largely attributable to reserve additions from Gulf of Mexico discoveries made in 1998. We did not make any significant acquisitions of proved properties in 1999 and wells drilled in 1999 did not account for a substantial portion of our production during the year, due to a typical time lag of several months between drilling a discovery in the Gulf of Mexico and first production. Additional properties brought on line in 1999 increased our production base in the Gulf of Mexico from 14 at the beginning of the year to 19 by the end of the year. We had six additional properties with discovery wells under development for initial sustained production as of December 31, 1999. We expect all of these are expected to commence producing during 2000.
Our capital expenditures totaled $81.9 million in 1999, before reflecting recoupments of $10.7 that resulted primarily from the sale of partial interests in exploratory prospects. Our 1999 capital investments principally related to exploratory drilling, development of discoveries made in 1999 or in the prior year, acquisitions of seismic data and exploratory leaseholds, and property exploitation activities. Our 1999 net capital investments of $71.2 million, after recoupments, were funded primarily with cash flow from operations, and the residual was funded with borrowings under a revolving line of credit with our banks. Although our capital investments exceeded cash flow from operations in 1999, we reduced our total debt during the year as the result of realizing approximately $67
million of net proceeds from a common stock offering completed in June 1999. Our long-term debt at the end of 1999 totaled $34 million, compared to $80 million at the beginning of the year.
To facilitate our continued exploration activities, we have assembled undeveloped leasehold positions totaling 313,061 gross acres, or 193,013 net acres, as of December 31, 1999. We have also acquired the rights to more than 1,100 lease blocks of 3-D seismic data covering portions of the Gulf of Mexico, which we have integrated with geological interpretations by our technical personnel to develop a multi-year inventory of 43 exploratory prospects in the Gulf as of December 31, 1999. We are also integrating 3-D seismic data in our prospect generation in the Rocky Mountain and onshore Gulf Coast regions.
See "Management's Discussion and Analysis of Financial Condition and Results of Operations" for additional discussion regarding the Company's history, current business activities and financial performance.
Business Strategy
Our goals are to generate per-share growth in reserves, production, earnings and cash flow through exploration, acquisition and development of oil and gas properties. We seek to achieve these objectives through the following strategies:
Explore in the shallow waters of the Gulf of Mexico. Our exploration activities are focused primarily in the shallow waters of the Gulf of Mexico. We believe that this region has significant remaining undiscovered reserves and that the combination of a substantial existing infrastructure of production platforms, pipelines, and processing facilities, and the effectiveness of 3-D seismic data, will reduce exploration risk and enhance project economics.
Capitalize on technical expertise. We have assembled teams of geoscientists and petroleum engineers with substantial experience and expertise in generating prospects, evaluating acquisition opportunities, and managing drilling and production operations. We intend to use this in-house capability to identify and pursue growth opportunities in the Gulf of Mexico and in selected areas onshore.
Apply advanced technology. We use advanced technologies, including 3-D seismic data and computer-aided exploration, to better define exploration prospects and development opportunites. Basin has acquired rights to more than 1,100 lease blocks of 3-D seismic data covering portions of the Gulf of Mexico, and we are in the process of acquiring 3-D data over several exploration prospect areas onshore.
Balance size and risk profile of exploration targets. We generally seek to conduct a drilling program that is balanced between exploration prospects with significant potential relative to our existing reserve base and smaller, lower risk prospects. This balance is intended to mitigate risk while providing exposure to meaningful growth in reserves and production.
Generate prospects internally. Our geoscientists internally generate prospects using our geological and geophysical databases and Landmark workstations. This allows us to retain large working interests and operating control and either to defray our capital investment by selling promoted interests or to increase our prospect inventory by swapping for interests in third-party generated prospects. We have internally generated more than 75% of our Gulf of Mexico prospects and we are currently focusing our efforts on internal generation of both offshore and onshore prospects.
Operate core properties. We operate properties accounting for more than 68% of our estimated proved reserves at December 31, 1999. Operating allows us to exercise greater control over the cost, timing and character of our exploration, development and production activities.
Pursue selective acquisitions. We actively seek to acquire interests in proved oil and gas properties with exploration or development potential to augment operations in our core areas and to establish positions in new areas.
Maintain financial flexibility. Basin seeks to maintain financial flexibility in order to pursue exploration and development activities and take advantage of acquisition opportunities. As of December 31, 1999, we had total debt of $34 million, leaving $56 million of our revolving line of credit undrawn. As of the same date, our total debt per Mcfe of estimated proved reserves was $0.16. Since we anticipate that our capital expenditures are likely to exceed cash flow from operations in the foreseeable future, periodic sales of assets or securities may be required, in addition to utilization of bank debt, in order to provide funds for such investments. At times, preservation or restoration of financial flexibility may be dependent on such sales of assets or securities.
Marketing
Basin sells its gas and natural gas liquids from Gulf of Mexico properties under short-term contracts of one year or less at market prices to various gas purchasers. These sales may involve delivery of gas to onshore points under firm or interruptible transportation agreements or sales at the wellhead. We sell oil from our Gulf of Mexico properties under short-term contracts at market prices. Basin enters into liquids transportation and separation agreements to deliver its condensate onshore, and generally sells its crude oil at the wellhead.
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, Basin does not anticipate that it will have difficulty in marketing its production in this region at prevailing spot market prices.
We sell the majority of our gas and natural gas liquids from fields in the Rocky Mountain region under marketing arrangements where prices received are responsive to changes in regional spot markets. These include short-term contracts under which gas is delivered and sold into interstate pipelines at market-sensitive prices, and long-term (often for the life of the lease) percentage-of-proceeds contracts with gas processors. We generally sell oil from our Rocky Mountain properties under term contracts that yield a premium over local posted prices.
We believe that the loss of one or more of our current oil or natural gas spot purchasers would not have a material adverse effect on our business because any individual purchaser would be readily replaceable by another purchaser who would be expected to pay approximately the same sales price.
Demand for natural gas is highly seasonal. As a result, the price received for spot market natural gas may vary significantly between seasonal periods. To date, Basin generally has been able to sell its available spot market natural gas at prevailing spot market prices, and our volumes sold have not fluctuated due to seasonality. There is no assurance, however, that we will be able to continue to achieve this result.
For much of the past decade, the markets for oil and natural gas have been volatile. We anticipate that such markets will continue to be volatile in the foreseeable future. Oil and gas price fluctuations have a significant impact on our business since virtually all of our operating revenues are ordinarily derived from sales of our oil and gas production. We periodically enter into oil and gas price hedging agreements as we deem conditions to warrant. Such transactions affecting the three-year period ended December 31, 1999, 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 ours, which may adversely affect our ability to compete successfully. In addition, many of Basin'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.
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.
Regulation of Sales and Transportation of Liquid Hydrocarbons and Natural Gas
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.
The transportation and sale of natural gas in interstate commerce is regulated under the Natural Gas Act ("NGA"), the Natural Gas Policy Act of 1978 ("NGPA") and regulations promulgated thereunder by the Federal Energy Regulatory Commission ("FERC"). The Natural Gas Wellhead Decontrol Act of 1989 deregulated all wellhead gas sales effective January 1, 1993. As a result, Basin's gas sales are not directly regulated.
After Basin's gas is produced and sold, its interstate transportation and resale is regulated by the FERC. 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 Basin's natural gas does not have a material direct impact on Basin, such regulation does have a material impact on the market for Basin's gas and the price Basin receives for its gas.
Commencing in the mid-1980s and continuing until the present, the FERC has adopted regulations designed to make interstate gas markets flexible and competitive. These regulations now require interstate pipelines to transport natural gas owned by others on a nondiscriminatory basis and have resulted in a flexible and competitive national market for natural gas. Current gas market conditions are a result of how the FERC has chosen to exercise its authority. The FERC retains authority to change these regulations. Basin has no reason to predict changes, but changes in the regulation of interstate gas transportation and resales could have a material impact on the market for Basin's gas production and the price Basin receives for its gas production.
The FERC has additional regulatory authority over pipelines operating on or across the OCS under the Outer Continental Shelf Lands Act (the "OCSLA"). The OCSLA requires all pipelines to provide open-access, non-discriminatory service. The OCSLA allows the FERC to exempt pipeline facilities meeting a statutory definition of "feeder lines" from the requirements of the OCSLA. The FERC has suggested that the nature of offshore operations and its separate regulatory authority under the OCSLA could justify broadening the definition of "gathering" in the OCS. Gathering is exempt from regulation under the NGA. Basin cannot predict what, if any, change in the regulation of OCS facilities will occur.
If the FERC decides that it should regulate fewer OCS facilities under the NGA, or if it is determined that the FERC's jurisdiction over crude oil and natural gas transportation on the OCS is more limited than previously asserted, Basin could face higher transmission costs for its OCS natural gas production and, possibly, reduced access to OCS transmission capacity. Upon the successful development of its offshore exploration prospects, Basin expects to own and operate facilities that Basin believes will be gathering lines. If the FERC decides to make it harder to qualify for the NGA gathering exception in the OCS, Basin's OCS facilities could be subject to regulation as interstate pipelines and that regulation could have a material impact on Basin.
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. Such regulation could be applied to restrict the rate at which Basin's wells produce oil or gas below the rate at which such wells would otherwise be produced, and the amount or timing of Basin's revenues could thereby be adversely affected.
Also in recent years, pressure has increased in states in which Basin has been active 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 Basin's drilling activities.
Environmental Matters
The drilling for and production, handling, transportation and disposal of oil and gas and by-products are subject to extensive regulation under federal, state and local environmental laws. In most instances, the applicable regulatory requirements relate to water and air pollution control and oilfield management measures, site restoration, permitting requirements, or restrictions on operations in environmentally sensitive areas such as coastal zones, wetlands and wildlife habitat. These requirements increase Basin's cost of doing business, delay or preclude operations, and create potential liability to governmental agencies or third parties for environmental damage. For example, environmental regulation may in some circumstances impose "strict liability" for environmental contamination, rendering an owner or operator or other person with a connection to a property liable for environmental and natural resource damages and cleanup cost without regard to negligence or fault on the part of such person. In addition, state laws often require some form of remedial action to prevent pollution from former operations, such as closure of inactive pits and plugging of abandoned wells, and such liability can be imposed on successor owners. In connection with its acquisitions, Basin generally performs environmental assessments. To the extent environmental liabilities have been identified in acquisitions to date, such liabilities are not material or we have 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 the trend toward stricter standards in environmental legislation and regulations is likely to continue. For instance, efforts have been made in Congress in the past to amend the Resource Conservation and Recovery Act to reclassify oil and gas exploration and 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 designated applicant (generally the operator) on behalf of the working interest owners to maintain proof of at least $35,000,000 of financial responsibility for each offshore facility (i.e., all wells, platforms and pipelines). However, higher degrees of financial responsibility (up to $150,000,000) are required if the estimated worst case oil spill discharge from a covered facility on the OCS is greater than 35,000 barrels. Offshore facilities in state waters are held to a financial responsibility of $10,000,000 for worst case oil spill discharges of up to 10,000 barrels, with higher amounts required (again up to $150,000,000) as the amounts of worst case spill discharges increase. 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 Basin or otherwise materially adversely affect Basin, the impact of these rules should not be any more adverse to Basin 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.
The Federal Water Pollution Control Act ("FWPCA") imposes restrictions and strict controls regarding the discharge of produced waters and other oil and gas wastes into navigable waters. Permits must be obtained to discharge pollutants to waters and to conduct construction activities in waters and wetlands. The FWPCA and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. Many state discharge regulations and the Federal National Pollutant Discharge Elimination System generally limit and may otherwise prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the oil and gas industry into coastal or offshore waters. Although the costs to comply with recently enacted zero discharge mandates under federal or state law may be significant, the entire industry is expected to experience similar costs and Basin believes that these costs will not have a material adverse impact on our results of operations or financial position. In 1992, the Environmental Protection Agency adopted regulations requiring certain oil and gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans.
The Federal Clean Air act, which is designed to be administered and enforced by individual state implementation plans, imposes permitting requirements and air emission limitations that can impact oil and gas activities.
The Endangered Species Act ("ESA") seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, nor destroy or modify the critical habitat of such species. Under the ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species or its habitat. The ESA provides for criminal penalties for willful violations of the Act. Other statutes provide protection to animal and plant species and may apply to Basin's operations, such as the Marine Mammal Protection Act, the Migratory Bird Treaty Act, and the National Historic Preservation Act.
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. 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 Basin's operations is conducted on public lands, both in the Gulf of Mexico and onshore. 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 and drilling limitations imposed by resource management plans. Moreover, on certain federal leases, prior approval of drillsite locations must be obtained from the Environmental Protection Agency. On large- scale projects, such as our Powder Mountain project, lessees may be required to perform Environmental Impact Statements to assess the environmental impact of potential development, which can delay project implementation or result in the imposition of environmental restrictions that could have a material impact on cost or scope.
Offshore leases in the Gulf of Mexico, beyond the limits of state ownership, are administered by the Minerals Management Service of the United States Department of the Interior (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 prior approval for exploration plans and development and production plans from the MMS and from adjacent states that have authorized programs under the Federal Coastal Zone Management Act. 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, construction, safety and operational specifications. The MMS also has regulations restricting the flaring or venting of natural gas or liquid hydrocarbons. 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 transportation pipelines associated with 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. While that Memorandum of Understanding was finalized in December 1996, the agency has not indicated that this regulatory review has been completed.
The MMS has entered into a series of Memoranda of Understanding with other federal agencies, such as the Environmental Protection Agency, Coast Guard, and Occupational Safety and Health Administration, providing for the MMS to undertake certain inspection and, in some cases, enforcement responsibility for the respective regulatory mandates of these agencies. Those agencies do, however, retain varying degrees of jurisdiction over OCS operations to establish and enforce regulatory requirements.
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. Basin is currently exempt from the supplemental bonding requirements of the MMS, but there is no assurance that such exemption will be maintained. In 1997, the MMS modified its regulations to, among other things, (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) increase the level of bond coverage for drilling deep stratigraphic test wells and (iv) 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 for end-of-lease obligations or certain other operations. These requirements could substantially increase Basin's current bonding liabilities, and could also impact Basin's residual liabilities, both with respect to existing leases acquired from third parties and with respect to leases that it may acquire or dispose of in the future.
Under certain circumstances, such as significant uncorrected safety violations, the MMS may require any operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect Basin's financial condition and operations.
The MMS has now finalized new rules that change significantly the principles for valuing crude oil for royalty payments on onshore and offshore federal leases. The new valuation retains the concept of gross proceeds for calculating royalties on production sold to third parties in arm's-length transactions. However, oil sold in non-arm's-length contracts will be valued using index pricing methods or other benchmarking procedures to determine a deemed arm's- length price. The rules define non-arm's-length sales to include sales to affiliates, certain exchange transactions, sales pursuant to certain call provisions, and other transactions. The breadth of these definitions could cause certain sales by Basin to be impacted and could in some cases require that it pay royalty on a deemed value higher than that which it actually receives for its oil. Basin does not expect the new rules to have a material impact on its royalty payments
In a series of new regulations and rulings, the MMS has also taken an expansive view of the lessee's duty to market natural gas on behalf of the Federal Government as lessor. For example, a new rule has disallowed the deductibility of certain transportation costs from the calculation of royalty on gas sold off federal leases, including marketer fees, cash out and other pipeline imbalance penalties, and long-term storage fees. The MMS has proposed changes to its lease forms to codify what it regards as the lessee's duty to market natural gas at no cost to the lessor and to assess royalty on sales by affiliates or other transactions off the lease. Although these new
regulations and rulings have been challenged judicially, the result of such challenges is impossible to predict. If the challenges fail, the impact of these regulations and rulings could be to increase Basin's costs of marketing production from federal leases and in effect impose royalty obligations on certain downstream sale transactions.
The MMS has also previously proposed gas valuation rules similar to those described above for oil royalty valuation, i.e., rules which would value gas sold in certain "non-arm's length" transactions in accordance with defined indices or other benchmarks. Those proposed rules were withdrawn in 1997, and it is not known whether the MMS intends to reissue them. The potential effect of such rules, as with the proposed oil royalty valuation rules, is to move the valuation point downstream for purposes of royalty calculation and thereby to impose a royalty obligation on a deemed value higher than proceeds realized by the lessee from sales netted back to the wellhead. Although Basin does not have marketing affiliates and does not currently market its production in exchanges or other transactions that appear to be the target of these regulatory proposals, Basin cannot predict how the final form of any of these rules could impact our royalty obligations.
Title to Properties
As is customary in the oil and natural gas industry, Basin makes only a cursory review of title to farmout acreage and to onshore undeveloped oil and natural gas leases upon execution of contracts for acquisition of leases. Prior to the commencement of drilling operations, a thorough title examination is conducted and curative work is performed with respect to significant defects. Basin performs complete reviews of title to federal and state offshore lease blocks and onshore producing properties prior to acquisition. To the extent title opinions or other investigations reflect material title defects, the seller of the property, rather than Basin, is typically responsible for curing any such title defects at its expense. If Basin 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, we could suffer a loss of our entire investment in the property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and gas industry. Our producing properties are mortgaged to our banks or are subject to a negative pledge in connection with our revolving credit facility.
Abandonment Costs
Basin is responsible for costs associated with the plugging of wells, the removal of facilities and equipment and site restoration on its oil and gas properties, pro rata to its working interest. As of December 31, 1999, Basin's total estimated undiscounted future abandonment costs for properties in federal waters in the Gulf of Mexico were approximately $15.5 million. For onshore properties, salvage values received for equipment are usually sufficient to offset abandonment costs. Estimates of abandonment costs and their timing may change due to many factors, including actual drilling and production results, inflation rates, and changes in environmental laws and regulations. We do not expect to incur significant abandonment costs in 2000. Estimated future abandonment costs are added to net unamortized historical oil and gas property costs for purposes of computing depreciation, depletion and amortization expense charges.
Employees
At December 31, 1999, Basin had 75 employees, including 11 employed in field operations and 64 employed in its Denver headquarters or Houston division office. None of Basin's employees are subject to a collective bargaining agreement and Basin considers its relations with its employees to be good.
Risk Factors
In addition to the other information set forth elsewhere in this Form 10-K, you should carefully consider the following factors when evaluating Basin.
Oil and gas prices fluctuate frequently, and low prices could have a material adverse impact on our business.
Prices for oil and gas fluctuate widely. Gas prices affect us more than oil prices, because most of our reserves and production are gas. At December 31, 1999, 64% of our estimated proved reserves consisted of gas on an Mcfe basis. In 1999, approximately 84% of our total production consisted of gas.
Basin's revenues, profitability and future rate of growth substantially depend on prevailing prices for oil, gas and gas liquids. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. The amount we can borrow from banks is subject to periodic re-determination based on changing expectations of future prices, among other factors. Lower prices may also reduce estimates of the amount of oil and gas that we can economically produce.
We cannot predict future oil and gas prices. Prices may decline from their 1999 levels.
Among the factors that can cause this fluctuation are:
. relatively minor changes in, and uncertainty surrounding, the supply of and demand for oil and gas; . the level of consumer demand, which can be affected by weather, economic conditions in the United States and other countries, and other factors; . impacts on supply from new technologies, equipment availability, capital market conditions, and other factors: . domestic and foreign governmental regulations; . the price and availability of alternative fuels; . political conditions in the Middle East; and . the price of oil and gas imports;
Hedging our production may result in losses.
We periodically enter into commodity hedging transactions, including energy price swap agreements and other financial arrangements in an effort to mitigate the potential impact of declines in oil and gas prices. Such arrangements involve risks. Hedging contracts limit the benefits we would realize if actual prices rise above the contract prices. We experienced hedging losses in 1999. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 1 of Notes to the Consolidated Financial Statements for a description of our recent hedging activity.
In addition, if our reserves are not produced at sufficient rates, we would be required to satisfy obligations under hedging contracts on potentially unfavorable terms without the ability to offset the financial impact through sales of comparable quantities of our own production. Further, the terms of our hedging contracts are based on many assumptions and estimates such as costs of transportation to delivery points. Under financial instrument contracts, we may be at risk for basis differential, which is the difference in the quoted financial price for contract settlement and the actual price received at the physical point of delivery. Substantial variations between our assumptions and estimates and actual results could materially adversely affect our results from operations. In addition, hedging contracts are subject to the risk that the other party may prove unable or unwilling to perform its obligations. Any significant nonperformance could have a material adverse financial effect on us.
The failure to replace our reserves would adversely affect our liquidity and operations.
Unless Basin conducts successful exploration or exploitation activities or acquires properties containing proved reserves, Basin's proved reserves will decline as those reserves are produced. The rate of decline depends on a number of factors, including drilling density, completion procedures, and reservoir characteristics. Further, decline rates vary from the generally steep declines experienced with production from reservoirs in the Gulf of Mexico, where we have most of our production, to the relatively slow declines of long-lived fields in the Rocky Mountain region, where our other producing properties are located. The market for acquiring proved reserves is extremely competitive, and we may not be able to buy reserves at reasonable prices. Basin's drilling operations may be unsuccessful. Our drilling operations also may be curtailed, delayed or canceled for many reasons, such as:
. title problems; . weather conditions; . compliance with governmental requirements; . cost overruns; . shortages of capital; . mechanical difficulties; and . shortages in drilling rigs or other equipment.
We may be unable to make the necessary capital investments to maintain or expand our oil and gas reserves if cash flow from operations is reduced and external sources of capital become limited or unavailable. We cannot assure you that our future acquisition, development and exploration activities will result in reserves added at acceptable costs.
Properties we buy containing proved reserves may not perform as we projected, and we may not be able to discover liabilities carried with the properties or obtain protection from sellers against them.
The successful acquisition of producing properties requires assessments of many factors, which are inherently inexact and may be inaccurate, including:
. the amount of recoverable reserves; . future oil and gas prices; . estimates of operating costs; . estimates of future development costs; and . potential environmental and other liabilities.
Our review will not reveal all existing or potential problems, nor will it permit us to become familiar enough with the properties to assess fully their deficiencies and capabilities. We may not inspect every well, platform or pipeline. We cannot necessarily observe structural and environmental problems, such as pipeline corrosion or groundwater contamination, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities they created. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.
Substantial acquisitions could require significant external capital and could change Basin's risk and property profile.
We frequently engage in bidding and negotiation for producing property acquisitions, many of which are substantial. If successful in this process, we may need to alter or increase our capitalization substantially to finance these acquisitions or joint ventures through the issuance of debt or equity securities, the sale of production payments or otherwise. These changes in capitalization may significantly affect our risk profile. Additionally, significant acquisitions or joint ventures can change the character of our operations and business. The character of the new properties may be substantially different in operating or geological characteristics or geographic location than our existing properties.
Exploration is a high-risk activity and the 3-d seismic and other advanced technologies we use are expensive, require experienced personnel, and cannot eliminate exploration risk.
Exploration activities are substantially more risky than development or exploitation activities or purchases of proved reserves. We use 3-D seismic data and other advanced technologies to reduce our risk, but exploratory drilling remains a speculative activity. Even when extensively used and properly interpreted, 3-D seismic data and visualization techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators. They do not conclusively allow the interpreter to know if hydrocarbons are present or if they are economically producible. The use of 3-D seismic data and certain other technologies also requires greater pre-drilling expenditures than traditional drilling strategies. Basin could incur losses as a result of such expenditures. Poor results from our exploration activities could have a material adverse effect on our future results of operations and financial condition.
Our principal focus area since 1996 has been the Gulf of Mexico. This operating area is highly competitive and our success there will depend on our ability to attract and retain experienced geoscientists and other professional staff. We currently have twelve geoscientists and petroleum engineers who are experienced in Gulf of Mexico operations. Loss of these experienced personnel could have a material adverse impact on Basin's ability to compete in this area.
If we cannot continue to access capital from external sources, we may be unable to expand our reserves and production.
Because our capital expenditures have generally exceeded our cash flow, we have required external sources of capital to develop and explore our properties and acquire additional properties. Our ability to continue to invest more than our cash flow will depend upon our access to additional capital, which will be determined by a number of factors, some of which are beyond our control. These include our operational success, the status of the capital markets, and oil and gas prices.
Historically we have addressed our long-term liquidity needs through cash flows from operations, bank borrowings and the issuance of equity securities. We continue to examine the following alternate sources of long-term capital:
. traditional reserve-based borrowings or the issuance of long-term debt; . the sale of common stock, preferred stock or other equity securities; . use of nonrecourse production-based financing or sales of net profits interests; . sales of non-strategic properties; . sales of interests in prospects and technical information; and . joint ventures.
We may be unable to execute our operating strategy if we cannot obtain capital from these sources. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources".
Outstanding debt could reduce our financial flexibility.
At December 31, 1999, our long-term debt equaled $34 million, and we had $56 million available to draw down under our revolving line of credit with our banks. Our working capital deficit equaled $10.4 million at December 31, 1999, leaving a net total of $45.6 million of unutilized credit capacity. Under our revolving line of credit, our banks redetermine our borrowing base at least semi-annually, and it is possible that any such review could result in a reduction of our borrowing base. This could occur as a result of weak oil and gas prices or unsuccessful exploration or development activities. The terms of our revolving line of credit may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general corporate purposes.
We wrote down the carrying value of our proved reserves at year-end 1998 to reflect low oil and gas prices, and we could experience such write-downs in the future.
The risk that we will be required to write down the carrying value of our oil and gas properties increases when oil and gas prices are low. In addition, write-downs may occur if we have substantial downward adjustments to our estimated proved reserves. Basin uses the full cost method of accounting to report operations for oil and gas properties. We capitalize the costs to acquire, explore for and develop oil and gas properties. Under full cost accounting rules, the net capitalized costs of oil and gas properties may not exceed a ceiling limit that is based on the present value of estimated future net cash flows from proved reserves, using constant oil and gas prices and a 10% discount factor, plus the lower of cost or fair market value of unproved properties. If net capitalized costs of oil and gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a ceiling limitation write-down. This charge does not affect cash flow from operating activities, but it does reduce the book value of our stockholders' equity. We review the carrying value of our properties quarterly, based on prices in effect as of the end of each quarter or as of the time of reporting results. We may not reverse write-downs even if prices increase in subsequent periods. Primarily because of weak oil and gas prices, we recorded a ceiling limitation write-down in the fourth quarter of 1998 in the amount of $38.5 million ($30.8 million after tax). We could have another ceiling limitation write-down in a future period if commodity prices decline significantly.
Our ability to market our oil and gas production depends on third parties and on fluctuating commodity prices and demand which are beyond our control.
Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business.
Demand for gas is highly seasonal. As a result, the price and marketability of our spot market gas may vary significantly between seasonal periods. If market factors dramatically change, the financial impact on Basin could be substantial. The availability of markets for our production is largely beyond our control.
A significant part of the value of our production is concentrated in a small number of offshore properties.
During the three months ended December 31, 1999, approximately 68% of our production was from seven properties in the Gulf of Mexico. If reservoir or mechanical problems, storms, or other events curtail production from one or more of our higher-rate properties, Basin's cash flow would be materially adversely affected.
Reserve estimates are inherently uncertain and depend on many assumptions that may turn out to be untrue.
The process of estimating oil and gas reserves is complex and inherently uncertain. It requires various assumptions, including assumptions required by the Securities and Exchange Commission with respect to future oil and gas prices, operating expenses, capital expenditures, taxes and availability of funds. We must project production rates and timing of development expenditures. We need to analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. Oil and gas reserve engineering is a subjective process of estimating accumulations of oil and gas that cannot be measured in an exact manner. Basin's proved reserve information included in this report represents only estimates prepared in part by independent petroleum engineers and in part by Basin engineers. Estimates from other engineers might differ materially from those shown. The accuracy of any reserve estimate is a function of the quality and quantity of available data, engineering and geological interpretation and judgment.
Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. In addition, we will adjust future estimates of proved reserves to reflect additional production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control.
At December 31, 1999, approximately 29% of our estimated proved reserves quantities were undeveloped. Recovery of undeveloped reserves generally requires significant capital expenditures. The reserve data assumes that we will make these expenditures. Although we estimate our reserves and the costs associated with developing them in accordance with industry standards, the estimated costs may not be accurate, development may not occur as scheduled, and results may not be as estimated.
You should not assume that the present value of future net cash flows referred to in this report is the current market value of our estimated oil and gas reserves. In accordance with Securities and Exchange Commission requirements, we generally base the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.
Fluctuations in our quarterly results of operations and other developments can cause sudden changes in the market price of our common stock.
Our quarterly results of operations may fluctuate significantly as a result of variations in oil and gas prices, production performance and changes in estimated proved reserves. The market price of our common stock may decline if our quarterly results decline or when announcements of adverse events regarding Basin or the industry are made.
The oil and gas business involves many operating risks that can cause substantial losses. Insurance may not be adequate to protect against all these risks.
The oil and gas business involves a variety of operating risks, including:
. fire; . explosion; . blow-out; . uncontrollable flows of oil, gas, or well fluids; . natural disasters; . pipe failure; . casing collapse; . stuck tools; . abnormally pressured formations; and . environmental hazards such as oil spills, gas leaks, pipeline ruptures and discharges of toxic gases.
If any of these events occur, Basin could incur substantial losses as a result of:
. injury or loss of life; . severe damage to and destruction of property, natural resources and equipment; . pollution and other environmental damage; . clean-up responsibilities; . regulatory investigation and penalties; and . suspension of operations.
If we experience any of these problems, it could affect wellbores, platforms, gathering systems or processing facilities, which could adversely affect our ability to conduct operations.
Offshore operations are subject to a variety of operating risks peculiar to the marine environment, such as hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities to third parties or governmental entities. Payment of these liabilities could reduce or eliminate the funds available for exploration, development or acquisitions, or result in loss of properties.
In accordance with industry practice, Basin maintains insurance against some, but not all, potential risks. Our coverage includes, but is not limited to, operator's extra expense, physical damage on certain assets, comprehensive general liability, automobile, and workers compensation insurance. We cannot assure you that our insurance will be adequate to cover our losses or liabilities. For example, insurance may not cover downhole operating risks, such as the costs of retrieving stuck equipment. Also, we cannot predict whether insurance will continue to be available at premium levels that justify its purchase.
Oil and gas operations are subject to extensive environmental and other governmental regulation, which can affect the cost, manner, or feasibility of doing business.
Development, production and sale of oil and gas are subject to extensive federal, state and local environmental and other governmental regulation. We have made and will continue to make large expenditures to comply with environmental and other governmental regulations. These regulations could change in ways that might substantially increase our costs. For example, the Minerals Management Service of the United States Department of the Interior has recently promulgated regulations for valuation of oil and gas produced from federal leases, including offshore leases, that could require payment of royalties on the basis of indices that may not reflect actual prices we receive for our production. Also, the Federal Energy Regulatory Commission has promulgated major regulatory initiatives over the past several years that have had a significant impact on gas pricing and gas pipeline operations, services and rates. Those changes have significantly altered the marketing of gas, and the effect of these changes on our ability to market our gas at reasonable prices is uncertain.
Offshore operations are subject to more extensive governmental regulation than onshore operations. Under the Outer Continental Shelf Lands Act, the Minerals Management Service regulates development and production of oil and gas in federal waters in the Gulf of Mexico, and it may suspend or terminate operations for violation of its rules. These and other environmental regulations could impose liability for pollution clean up and damages and require cessation of operations in affected areas. Any such costs, damages, suspension or termination could materially and adversely affect Basin's financial condition and operations.
We are subject to state and local regulations that impose permitting, reclamation, land use, conservation, and other restrictions on our ability to drill and produce.
Competition in our industry is intense and we are smaller than many of our competitors in the Gulf of Mexico.
We compete with major and independent oil and gas companies for property acquisitions, especially in the Gulf of Mexico. We also compete for the equipment and labor required to operate and develop such properties. Most of our competitors have financial and other resources substantially greater than ours.
We cannot control the pace or type of activities on properties that we do not operate.
Some of our properties are operated by third parties. Because we are not the operator, we do not have the ability to control the nature of operations undertaken, such as the drilling of exploration and development wells, or the timing of such operations. This can affect our capital expenditures, production levels and cash flow.
Our principal stockholder is in a position to affect corporate transactions and other matters.
Basin's principal stockholder, Michael S. Smith, together with members of his immediate family and trustees for their benefit, beneficially own approximately 15% of Basin's outstanding shares of common stock. As a result, Mr. Smith is in a position to substantially influence the outcome of stockholder votes on the election of directors and other matters. In addition, if Mr. Smith were to sell a significant number of his shares, the prevailing market price of Basin's common stock could be adversely affected.
The loss of Michael S. Smith or other senior personnel could adversely affect Basin.
We depend to a large extent on the services of our founder and Chief Executive Officer, Michael S. Smith, and certain other senior management personnel. The loss of the services of Mr. Smith or other key personnel could have a potential adverse effect on Basin's operations.
Anti-takeover provisions adopted by Basin could deter change of control transactions.
Basin's restated certificate of incorporation and bylaws and the provisions of the Delaware General Corporation Law make it more difficult to change control of Basin and replace incumbent management. We adopted a stockholders' rights plan in 1996. Under this plan, holders of our common stock received rights exercisable if a person or group of affiliated persons acquires 15% of our outstanding common stock or commences a tender or exchange offer that would result in ownership of 15% or more of our outstanding common stock. Basin has a classified board of directors under which directors serve staggered three-year terms, which may hinder or prevent replacement of the entire board of directors by stockholders at any one meeting. In addition, we have entered into agreements with certain of our executive officers that would require us to make additional payments if such officers' employment were terminated, or the terms of such employment were materially altered, upon a change of control.
ITEM 2.
ITEM 2. PROPERTIES.
Prior to 1996, our 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, we sold our D-J Basin properties, which represented approximately 70% of our fixed assets at the time, and initiated operations in the Gulf of Mexico. Our subsequent investment activities through 1999 have been focused predominantly on Gulf of Mexico properties. As of December 31, 1999, our estimated proved reserves totaled approximately 12.6 million barrels of oil and 134.1 Bcf of natural gas, or 209.5 Bcfe. The estimated pre-tax present value of future net revenues from these proved reserves, using December 31, 1999 product prices held constant and a discount rate of 10%, totaled approximately $269.3 million. Gulf of Mexico properties accounted for 64% of our proved reserve quantities at December 31, 1999 and 77% of the related pre-tax present value of future net revenues estimated as of that date. Weighted average prices used for purposes of estimating proved reserves at December 31, 1999 were $24.39 per barrel of oil and $2.32 per Mcf of natural gas.
In addition to our proved properties as of December 31, 1999, we owned mineral rights under 313,061 gross, or 193,013 net, undeveloped acres. We also have acquired the rights to 3-D seismic data covering approximately 1,100 lease blocks, and 2-D data covering approximately 375,000 miles, in the Gulf of Mexico. Our undeveloped acreage in the Gulf of Mexico at the end of 1999 contained 43 exploratory prospects identified by Basin's geoscientists, based upon their interpretations of 3-D seismic and other data.
Our Gulf of Mexico proved reserves as of December 31, 1999 were distributed among 25 properties. Production had been established from 19 of these fields at that date, and the other six fields were under development for first production. Our working interests in the 25 properties ranged from approximately 8% to 100%, with an average of 51%. Eleven of the 25 properties account for approximately 72% of our proved reserve quantities and 74% of the related pre-tax present value of future net revenues from our Gulf of Mexico assets as of December 31, 1999. Basin operates 16 of the 25 properties. These 16 properties account for approximately 67% of our total proved reserves in the Gulf of Mexico. As is generally the case for Gulf of Mexico properties, we expect our properties in this area to exhibit a high initial production rate followed by a steep decline in production after a relatively short period.
Most of the proved reserves value related to our onshore assets as of December 31, 1999 was concentrated in six fields in the Powder River and Green River Basins. This value was broadly distributed among approximately 200 producing wells, as well as a number of undeveloped locations. Most of our producing wells in the Rocky Mountain area have been on-line for several years and their respective production declines are relatively moderate and well-established.
Additional information related to our properties is set forth below in the balance of this section.
Oil and Gas Reserves
Basin engaged Ryder Scott Company Petroleum Engineers, independent petroleum engineers, to prepare estimates of proved reserves, projected future production, and related future net revenues for certain of our properties as of December 31, 1999, and to audit our estimates of such data for Basin's remaining properties as of that date. The estimates prepared by Ryder Scott Company Petroleum Engineers covered properties that accounted for 28% of our proved reserve quantities in the Gulf of Mexico as of December 31, 1999, and audits conducted by Ryder Scott Company covered the other properties. Estimates prepared by Ryder Scott Company or our engineers were based upon a review of production histories and other geologic, economic, ownership, volumetric and engineering data. In estimating reserve quantities that are economically recoverable, oil and gas prices and estimated development and production costs as of December 31, 1999 were utilized.
The following table sets forth estimates as of December 31, 1999 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 our estimated proved oil and gas reserves. For additional information concerning the present value of future net revenue from these proved reserves, see Unaudited Supplemental Oil and Gas Reserve Information in the Notes to the Consolidated Financial Statements.
The following table sets forth estimates of Basin's total proved reserves at December 31, 1999 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 future geologic success, prices, production levels and costs that may not prove correct. 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 our proved reserves and future net revenues therefrom as of December 31, 1999 were $24.39 per Bbl for oil and $2.32 per Mcf for gas.
As an operator of domestic oil and gas properties, the Company has filed Department of Energy Form EIA-23, "Annual Survey of Oil and Gas Reserves," as required by Public Law 93-275. There are differences between the reserves as reported on Form EIA-23 and as reported herein. The differences are attributable to the fact that Form EIA-23 requires that an operator report on the total reserves attributable to wells that it operates, without regard to ownership (i.e., reserves are reported on a gross operated basis, rather than on a net interest basis).
Acreage
The following table sets forth the gross and net acres of developed and undeveloped oil and gas leases held by Basin as of December 31, 1999.
____________
/1/ Developed acreage is acreage assigned to producing wells for the spacing unit of the producing formation. Developed acreage in certain of Basin's properties that include multiple formations with different well spacing requirements might be considered undeveloped for certain formations, but have only been included as developed acreage in the presentation shown.
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.
/1/ excluding hedging effects
Basin owned 262 gross (177 net) producing oil wells and 71 gross (42 net) producing gas wells as of December 31, 1999. A well is categorized under government 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.
/1/ Excludes $1,113,000, $150,000 and $9,995,000 of costs recouped through the resale of partial interests in prospects to industry partners in 1997, 1998 and 1999, respectively.
Drilling Activity
The following table sets forth the wells drilled and completed by Basin during the periods indicated.
Present Activities
On March 15, 2000, Basin submitted apparent winning bids for ten tracts at the Central Gulf of Mexico lease sale held by the Minerals Management Service. Such tracts comprised 43,526 gross and net undeveloped acres offshore Louisiana. If all ten tracts are awarded by the Minerals Management Service, which can choose to reject all bids for a given lease, our aggregate cost for the related leasehold bonuses will total approximately $5.7 million.
During 2000, through March 27, Basin's Gulf of Mexico activities have included completion of four (1.8 net) wells that were successfully drilled in 1999, drilling of three (1.7 net) exploratory wells, of which two (1.3 net) well were apparent discoveries. Basin also participated in the completion of one (0.2 net) well in Wyoming.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
Basin is not currently involved in any material legal proceedings.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
No matters were submitted for a vote of our security holders during the fourth quarter of 1999
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SHAREHOLDER MATTERS.
Basin's common stock began trading on the NASDAQ National Market System on May 13, 1992 under the symbol "BSNX". As of December 31, 1999 there were approximately 2,000 beneficial owners of the Company's common stock. The following table sets forth, for the periods indicated, the range of high and low sales prices, and the closing price at the end of the period, for Basin's common stock as reported by the Nasdaq National Market for the last two calendar years.
Our policy is to retain earnings to support the growth of our business. Accordingly, Basin's Board of Directors has never declared a cash dividend on our Common Stock and has no present plan to do so. A credit agreement with our bank group limits our ability to pay dividends, re-acquire shares of Basin's common stock or make certain other distributions.
During 1999, Basin had no sales of securities that were not registered under the Securities Act of 1933, except the issuance of 37,045 shares of common stock pursuant to the cashless exercise of warrants issued by us on November 30, 1994 covering a total of 122,572 shares. Warrants covering a total of 49,760 shares of Basin common stock expired on December 31, 1999. The warrants (and the shares issued pursuant to exercise of the warrants) were issued in reliance upon the exemption from registration under Section 4(2) of the Securities Act of 1933, as amended, relative to sales by an issuer not involving a public offering.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
The following table sets forth selected consolidated financial data for Basin as of the dates and for the periods indicated. The data set forth in this table should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Consolidated Financial Statements and the related notes thereto that follow.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Basin's consolidated financial statements and the accompanying notes contain additional detailed information that should be referred to when reviewing this material.
Statements in this discussion may be forward-looking. Such forward-looking statements involve risks and uncertainties that could cause actual results to differ significantly from those expressed. See "Forward-Looking Statements."
History and Overview
Basin Exploration, Inc. is a domestic independent oil and gas company that conducts exploration, acquisition and production activities in the shallow waters of the Gulf of Mexico and selected areas onshore.
We commenced operations in 1981 and completed an initial public offering of common stock in 1992. From our inception through 1991, we primarily acquired and developed properties in the Denver-Julesberg Basin in eastern Colorado. In 1992, we began expanding into other areas within the Rocky Mountain region and initiated exploration activities.
During 1995, our capital expenditures on oil and gas properties declined to $16 million from $67 million the year before. This decline occurred primarily because of reduced quality investment opportunities in our core operating areas and limitations on our borrowing capacity under our revolving line of credit. Depressed regional gas prices contributed to both of these factors.
In response to these developments and our management's assessment of alternative investment opportunities, we implemented a significant redirection of our business strategy and operations between late-1995 and mid-1996. The redirection included:
. adding new financial, technical and business development members to our senior management; . selling our Denver-Julesberg Basin properties for $123.5 million; . creating a Houston-based Gulf of Mexico exploration team through hiring geoscientists and petroleum engineers with substantial experience operating in the area; . acquiring a substantial database of newly available regional 3-D seismic data and Landmark workstations for our Gulf of Mexico geoscientists to use in prospect generation; and . reducing corporate staff and general and administrative overhead.
The sale of our Denver-Julesberg Basin assets enabled us to eliminate our long- term debt and establish cash reserves, providing us with liquidity for investments in new capital projects. The sale, however, resulted in a significant initial decline in our revenue and cash flow, as the assets sold accounted for approximately 70% of our production and estimated proved oil and gas reserves at the time.
We began our Gulf of Mexico activities in 1996 with no initial property base in the region and our early investments related primarily to acquisitions of 3-D seismic data and exploratory leasehold interests. Our first significant discovery in the Gulf of Mexico was the Eugene Island Block 65 #1 well, which we began drilling at the end of 1996 and completed in 1997. Our first production from Gulf of Mexico assets occurred in August 1997, when we brought two wells drilled on Eugene Island Block 65 on-line. We added other proved properties in the Gulf of Mexico in 1997, 1998 and 1999 through both exploratory drilling and acquisitions. As of December 31, 1999, we owned interests in 25 properties with proved reserves in the Gulf of Mexico, of which six were under development for first production. Basin's estimated proved oil and gas reserves increased from 62.6 Bcfe as of December 31, 1995, pro forma the sale of our Denver-Julesberg properties, to 209.5 Bcfe at the end of 1999. As further described below, our net production has grown significantly since mid-1997, as additional Gulf of Mexico properties have been brought on-line.
During 1997, 1998, and 1999, our capital expenditures on oil and gas activities, net of costs recouped through the resale of partial interests in prospects to industry partners, totaled approximately $105.6 million, $106.7 million
and $71.2 million, respectively. Over 90% of these investments related to our operations in the Gulf of Mexico, including costs that we incurred for exploratory leaseholds, geological and geophysical data, exploratory drilling, completion and development activities, and acquisitions of proved properties. Although our net capital expenditures were lower in 1999 than in 1998, we were able to drill a greater number of wells in 1999, due to reduced costs for oil field services and less net investment for prospect inventory accumulation. From the beginning of 1996, when we initiated operations in the Gulf of Mexico, through the end of 1999, Basin drilled a total of 52 wells in the Gulf, of which 35, or 67%, were successful.
We closed 1999 with a working capital deficit of approximately $10.4 million, long-term debt of $34.0 million, and stockholders' equity of $175.2 million.
Operating Environment
Oil and gas price levels, which are volatile and beyond our control, significantly impact our results of operations. Changes in oil and gas prices can also affect the amount and terms of external capital resources available to Basin. Generally, periods of low oil and gas prices are characterized by decreased costs for oilfield services and property interests and reduced competition for investment opportunities, partially mitigating the effects of price level changes.
Gas prices generally respond to North American supply and demand conditions, including the effects of weather. Oil prices reflect global supply and demand conditions to a greater degree, including the impact on supply of decisions by petroleum exporting countries. Despite temporary periods of interrupted growth, oil and gas demand has generally increased over time. Short-term fluctuations in demand, however, can significantly impact prices. During most of 1998 and the first quarter of 1999, the markets for both oil and gas generally reflected ample supply and price weakness due to a number of factors, including a second consecutive unusually warm winter in North America. Since mid-March 1999, oil and gas prices have increased, apparently in response to production cut-backs by petroleum exporting countries, expectations of reduced domestic productive capacity caused by declines in drilling activity, and demand growth associated with economic expansion. There are well-developed futures markets for oil and gas that provide indications of expected future prices for each product. These prices are often substantially different than current prices reflected on spot markets. Presently, these futures markets reflect expectations of relatively strong average prices for oil and gas in 2000, compared with the past several years. Expectations will change in response to future developments and indicated future prices may not actually materialize.
Hedging transactions can be entered into based on prices reflected in commodity futures markets. We periodically enter into fixed price sales agreements or other hedging transactions. We do this to take advantage of prices that we believe to be attractive and to reduce risks related to potential price declines, including the risk of being unable to make capital investments at targeted levels. Because we do not ordinarily enter into hedges that would cover all of our anticipated production for any given time period, we remain vulnerable to the effects of a decline in prices even when hedging positions are established. Hedging contracts also can reduce the benefits realized by Basin from increases in oil and gas prices. See "Risk Factors--Hedging our production may result in losses".
Our Gulf of Mexico exploration activities are dependent on our ability to continue to identify and obtain prospects. We generally use non-proprietary three-dimensional seismic data, which is also available to our competitors, as a tool in our prospect generation. This tends to increase competition for, and cost of, available prospects. Since beginning exploration in the Gulf of Mexico, we have successfully expanded our inventory of potential exploratory drilling locations from zero to 43 at the end of 1999, while drilling 46 test wells. This inventory of prospects, the majority of which are 100%-owned by Basin, represents more than a two-year set of drilling opportunities, based on our historical and anticipated drilling activity levels. However, we face competition for additional prospects from many better-capitalized oil and gas companies. There is no assurance that over the longer term we will be able to continue to acquire interests in prospects at acceptable costs to replenish our inventory of prospects as these are drilled. See "Risk Factors--The failure to replace our reserves would adversely affect our liquidity and operations." Basin seeks to mitigate this risk by pursuing prospect ownership through a number of avenues, including lease sales, farm-ins, exchanges, and acquisitions. We also plan to selectively evaluate and pursue other investment opportunities, including onshore exploration and acquisitions of properties with proved oil and gas reserves, to complement our core exploration activities in the Gulf of Mexico.
Results of Operations
The table of operating and financial data shown below and the discussion that follows are provided to assist you in understanding our results of operations for the periods presented.
1999 Compared to 1998
Revenue. Oil and gas sales revenue for the year ended December 31, 1999 totaled $71.5 million, representing an increase of $22.9 million, or 47%, compared to 1998. A 48% increase in net oil and gas production was negligibly offset by a less than 1% decline in average realized unit prices (net of hedging effects), based on net equivalent unit measures. The increase in oil and gas production was attributable primarily to initiation of production from discoveries drilled in the Gulf of Mexico in 1998 and early 1999. During 1999, we obtained production from 19 Gulf of Mexico properties, compared to 14 in the prior year. Due to the additional Gulf of Mexico production, which is predominantly gas, and lower oil production from onshore properties on which investments were deferred during the first half of 1999 due to low oil prices, gas increased from 80% of net equivalent units produced in 1998 to 84% of total oil and gas production in 1999. See "Liquidity and Capital Resources" for additional discussion of our oil and gas production. Hedging transactions had the effect of increasing oil and gas sales in 1998 by $3.5 million, or $0.16 per Mcfe, while decreasing oil and gas sales in 1999 by $7.0 million, or $0.21 per Mcfe.
Lease Operating Expenses. Due to an increased number of producing properties and higher production levels, lease operating expenses for the year ended December 31, 1999 increased by $2.5 million, or 30%, from the amount reported for the prior year. However, lease operating expenses per Mcfe produced declined by 13%, from $0.38 in 1998 to $0.33 in 1999, due to increased production in the current period from Gulf of Mexico wells, which typically have significantly lower average unit operating costs than our Rocky Mountain properties.
Production Taxes. Production taxes for the year ended December 31, 1999 totaled $0.9 million, representing an increase of $0.1 million, or 19%, compared to 1998. The increase was attributable to greater revenue from our onshore properties in 1999, principally due to higher oil prices. The increase related to prices was partially offset by reduced tax rates on new production and revisions to previous estimates. Production taxes as a percentage of oil and gas sales for the year ended December 31, 1999 were 1.3%, compared to 1.6% in 1998, due to a greater portion of sales in 1999 attributable to properties in federal waters offshore, which are generally not subject to production taxes.
Depreciation, depletion and amortization. Depreciation, depletion and amortization expense for the year ended December 31, 1999 was $39.5 million, representing an increase of $9.7 million, or 33%, compared to 1998. The increase was attributable to the 48% increase in production volumes in 1999, as compared to 1998, offset by a decrease in the per-unit depletion rate. The depletion rate of $1.19 per Mcfe produced in 1999 represented a 9% reduction from the $1.31 per Mcfe average depletion rate during the 1998 period. The lower rate is principally due to the effects of a property impairment charge recorded in the fourth quarter of 1998.
General and administrative, net. General and administrative expenses were $4.9 million in 1999, net of overhead reimbursements and amounts capitalized. This represented an increase of $1.0 million, or 25%, as compared to 1998. The increase resulted primarily from incremental costs incurred to manage expanded operations in the Gulf of Mexico. General and administrative expenses increased at a slower rate than production, resulting in a 17% decline in general and administrative expenses per Mcfe produced, from $0.18 in 1998 to $0.15 in 1999.
Stock compensation, net. Stock compensation expense for the year ended December 31, 1999, net of amounts capitalized, was $1.2 million, representing an increase of $0.8 million, or 173%, as compared to 1998. The increased expense reflects, in part, appreciation in the price of Basin's common stock from $12.56 per share at December 31, 1998 to $17.63 per share at December 31, 1999. Stock compensation expense relates to annual grants to employees of restricted stock, including shares awarded to senior management that will be earned only if certain performance measures are achieved by Basin. Expense is recognized based on vesting schedules, projections of performance, and changes in the price of our common stock during the applicable vesting period.
Interest expense. Interest expense for the year ended December 31, 1999 totaled $2.3 million, representing an increase of $0.3 million, or 12%, compared to 1998. The variance was attributable to an increase in average borrowings and higher average effective interest rates. During 1999, Basin had average outstanding debt of $61.1 million, with an average effective interest rate of 6.7%, compared to average debt of $53.4 million and an average interest rate of 6.6% in 1998. Interest capitalized to unproved property costs in accordance with Statement of Financial Accounting Standards No. 34 was $2.0 million in 1999, as compared to $1.5 million in 1998.
Income tax benefit (provision). The difference between the income tax benefit recorded for 1998 and the amount that would be calculated by applying statutory income tax rates to the loss before income taxes is due primarily to the establishment of a $5.7 million deferred tax asset valuation allowance. No net income tax expense was recorded in 1999 due to utilization of $4.2 million of this deferred tax asset valuation allowance.
1998 Compared to 1997
Revenue. Oil and gas sales for 1998 increased over the prior year by 99%, to $48.6 million. This increase resulted from a 154% increase in combined oil and gas production volumes, partially offset by a 22% decrease in revenue per net equivalent unit produced. Our average net realized oil and gas prices declined from $2.82 per Mcfe in 1997 to $2.21 per Mcfe in 1998. Hedging transactions had the effect of reducing our oil and gas sales in 1997 by $0.5 million, or $0.06 per Mcfe, and increasing sales in 1998 by $3.5 million, or $0.16 per Mcfe.
We established our first production from Gulf of Mexico assets in the second half of 1997. The 154% increase in production volumes in 1998 was attributable to greater contributions from five offshore properties that were acquired or brought on-line during the second half of 1997 and to the commencement of production at nine additional offshore properties at various times during 1998. These additions were partially offset by natural production declines.
Lease Operating Expenses. Lease operating expenses increased in 1998 from the prior year by $3.7 million, or 80%, but lease operating expense per Mcfe produced declined by 28% to $0.38, from $0.53 in 1997. Basin's lease operating expense per Mcfe generally improved on a per-unit basis as Gulf of Mexico production increased, beginning with the third quarter of 1997. Typically, our Gulf of Mexico properties have significantly lower unit operating costs per unit of production than our Rocky Mountain assets. The relatively low per-unit operating cost of our Gulf of Mexico properties is attributable to higher average production rates per well and a higher proportion of gas production, which is generally less costly to produce than oil.
Production taxes. Production taxes for 1998 decreased from 1997 by $0.5 million, or 39%, as the result of reduced sales revenue from onshore properties. This reduction reflects both lower production from onshore assets and lower prices received for such production. Production from our properties in federal waters in the Gulf of Mexico is generally not subject to production taxes, accounting for the decline in production taxes as a percentage of oil and gas sales, from 5.2% in 1997 to 1.6% in 1998.
Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased by 180%, from $10.6 million in 1997 to $29.8 million in 1998. Most of this increase was attributable to a 154% increase in production volumes. The average depletion rate (which excludes depreciation related to non-oil and gas assets) of $1.31 per Mcfe of production in 1998 represents a 17% increase from the $1.12 per Mcfe recorded in 1997. The higher rate is due to a reduction of estimated proved reserves attributable to lower oil and gas prices at the end of 1998 than one year earlier, and to a cost for proved reserves added in 1998 that was above Basin's historical average. The increased unit cost of additions in 1998 reflects the substantial portion of our capital expenditures in 1998 related to the Gulf of Mexico, where higher unit costs are associated with reserves that generally have a higher value per unit than our onshore properties, due to faster recoveries of reserves, lower production costs, and higher average realizable gas prices.
General and administrative expenses, net. General and administrative expenses in 1998 increased by 21% from 1997 levels, to $3.9 million. The increase in 1998 resulted primarily from incremental costs incurred to manage expanded operations in the Gulf of Mexico. On a per-unit basis, general and administrative expenses generally declined during the two-year period as production volumes increased, and averaged $0.18 per Mcfe of production in 1998 compared to $0.38 per Mcfe in 1997.
Stock compensation, net. Stock compensation expense for the year ended December 31, 1998, net of amounts capitalized, was $0.5 million, representing an increase of less than $0.1 million, or 3%, as compared to 1997. Stock compensation expense relates to annual grants to employees of restricted stock, including shares awarded to senior management that will be earned only if certain performance measures are achieved by Basin. Expense is recognized based on vesting schedules, projections of performance, and changes in the price of our common stock during the applicable vesting period.
Interest and other expense. Interest and other expense for 1998 totaled $2.0 million, representing an increase of $1.3 million, or 166%, compared to 1997. The increase was attributable to greater average borrowings outstanding offset by a slight reduction in Basin's average effective interest rate. During 1998, Basin had average outstanding debt of $53.4 million with an average effective interest rate of 6.6%, compared to average borrowings of $10.2 million and an average effective interest rate of 6.7% in 1997. Substantially all of the borrowings in both years were under our revolving line of credit. Interest expense in 1998 excludes $1.5 million of interest capitalized to unproved property costs in accordance with Statement of Financial Accounting Standards No. 34.
Property impairment. During 1998, we recognized a property impairment charge of $38.5 million as the result of the capitalized costs of our oil and gas properties exceeding a "ceiling" on such costs computed in accordance with prescribed guidelines for companies utilizing the full cost accounting method. The charge, which had no impact on our cash flows or our revolving line of credit, was associated with unusually low oil prices in effect at the end of 1998. Additional discussion of the charge, including information regarding the methodology prescribed for computing the full cost ceiling, is presented in Note 1 to the Consolidated Financial Statements.
Income tax provision. The difference between the income tax benefit recorded for 1998 and the amount that would be calculated by applying statutory income tax rates to the loss before income taxes is due primarily to the establishment of a $5.7 million deferred tax asset valuation allowance. The income tax provision for 1997 approximates the amount that would be calculated by applying statutory income tax rates to income before income taxes.
Liquidity and Capital Resources
Historically, Basin's principal sources of capital have been cash flow from operations, borrowings under a revolving line of credit, proceeds from asset sales, and proceeds from sales of common stock. Our principal uses of capital have been for the exploration, acquisition, and development of oil and gas properties.
Basin's gross accrual-basis capital expenditures during 1999 totaled approximately $81.9 million. Net capital expenditures totaled approximately $71.2 million, after reflecting $10.7 million of proceeds from asset sales, which primarily represented recoupments from partners upon sales of partial interests in prospects. Our principal sources of funds in 1999 were $52.8 million of net cash provided by operations before changes in working capital, and $67.1 million of net proceeds from the sale of common stock. During 1999, we used these funds to repay $46 million of long-term debt and to increase our net working capital by $2.8 million, in addition to funding our net capital investments. At the end of 1999, we had a working capital deficit of approximately $10.4 million and long-term debt outstanding under our revolving line of credit of $34.0 million. The borrowing base established under our revolving line of credit is currently $90 million.
Production and cash flow. Our cash flow from operations is generally determined primarily by our production level and realized oil and gas prices. Since 1996, we have made significant investments to initiate and then expand our operations in the Gulf of Mexico. These investments have resulted in an increase in our production from an average rate of 11.2 MMcfe per day in the second quarter of 1997, prior to commencement of Gulf of Mexico production, to an average of 89.1 MMcfe per day in 1999.
Based primarily on estimates reflected in our year-end 1999 reserve reports, we anticipate that our net production in 2000 will be at least 10% greater than during 1999, when production totaled 32.5 Bcfe. The expected increase is attributable primarily to projected production from Gulf of Mexico properties with proved reserves at the beginning of 2000 that were either on-line for only a portion of 1999 or had not yet commenced producing. Partially offsetting these additions will be natural depletion-related declines in production from existing producing wells. Actual realization of the production increases projected for 2000 will be dependent upon meeting scheduled dates for commencement of production from wells not yet on-line at the end of 1999, and upon achieving projected performance from major wells, including certain wells with little or no production history. Although management and our independent petroleum engineering consultants believe the projections are reasonable, there is no assurance that they will be met. See "Risk Factors--Reserve estimates are inherently uncertain and depend on many assumptions that may turn out to be untrue." and "Summary--Forward-Looking Statements" for a description of certain risks that may impact our ability to achieve projected production levels.
Marketing and hedging transactions. Basin's production is generally sold under month-to-month contracts at prevailing prices. From time-to-time, however, as we think conditions warrant, we have entered into hedging transactions or fixed price sales contracts for a portion of our oil and gas production. The purposes of these transactions are to limit Basin's exposure to future oil and gas price declines and achieve a more predictable cash flow, and to take advantage of prices that we view as attractive. However, such contracts also limit the benefits we would realize if prices increase. Hedging transactions had the effect of increasing oil and gas sales by $3.5 million, or $0.16 per Mcfe, in 1998, while decreasing oil and gas sales by $7.0 million, or $0.21 per Mcfe, in 1999. See "Risk Factors--Hedging our production may result in losses".
Through February 4, 2000, Basin had entered into the following fixed price swap arrangements covering the period beginning January 1, 2000 (one MMBtu approximates one Mcf of gas):
As of February 4, 2000, Basin had also sold call options for 10,000 MMBtu of gas per day for the period from January 2000 through December 2001, at an average strike price of $2.50 per MMBtu. At December 31, 1999, the estimated fair value of the open oil and gas price hedging contracts was an unrealized loss of approximately $3.1 million.
Revolving line of credit. Effective January 1, 1999, and as subsequently amended, we entered into a credit agreement with our existing bank group that provides for borrowings of up to $150 million. The maximum amount that we can draw is limited to the borrowing base that is periodically established by the bank group. Interest rates applied to borrowings under the credit agreement are determined by reference to the prime rate or
LIBOR, at our election. A varying spread of 0% to 0.25% is added to the prime rate, or a spread of 0.75% to 1.5% is applied to LIBOR, based upon our facility usage ratio. Our credit agreement contains various covenants, including limitations on our ability to incur other debt, dispose of assets, pay dividends, or repurchase stock. Pursuant to our credit agreement, substantially all of our producing properties are subject to mortgages in favor of the banks and our remaining properties are subject to a negative pledge.
Our credit agreement provides for borrowings to be revolving loans until November 30, 2002, at which time the outstanding balance will be converted into a four-year amortizing term loan unless the credit agreement is amended. The borrowing base under the credit agreement is scheduled to be re-determined at six-month intervals until the revolving loan is converted into a term loan. Our borrowing base is currently set at $90 million, and the next re-determination is scheduled to occur as of June 1, 2000. Borrowing base re-determinations conducted by the bank group reflect a number of estimates and assumptions including, but not limited to, future production from Basin's proved properties, risk factors for estimates of proved reserves, future oil and gas prices, future operating and development costs, and future interest rates. Changes in such estimates and assumptions can significantly impact the size of the borrowing base established by the banks. Because these factors will be influenced by future events, which cannot be forecast with certitude, we cannot predict what level of borrowing base will be established at any future determination date.
The weighted average interest rate on borrowings outstanding under the credit agreement at December 31, 1999 was 7.1%. Our annual interest costs will fluctuate based upon changes in short-term interest rates and borrowings outstanding. Assuming debt outstanding during 2000 remained unchanged from the amount outstanding at December 31, 1999, the annual impact on interest expense of a ten percent change in the average interest rate would be approximately $0.2 million, before amounts capitalized. As the interest rate is variable and is reflective of current market conditions, the carrying value of Basin's debt approximates its fair value.
Positive or negative changes in the borrowing base during 2000 could impact the level of our capital expenditures during the year. Increases, supported by performance of our properties, drilling results, and/or higher oil and gas prices, could improve our ability to grow. Decreases would adversely affect our liquidity and capital resources, potentially resulting in a reduction of planned capital expenditures or the sale of assets or the issuance of securities.
Capital expenditures. Since the beginning of 1996, we have focused our exploration activities in the shallow waters of the Gulf of Mexico, primarily off the coast of Louisiana. During the second half of 1998 we began to direct a relatively small portion of our exploration budget toward onshore opportunities. In addition to our exploration activities, we also pursue property acquisition opportunities in the vicinity of our Gulf of Mexico exploration operations, in the Rocky Mountain region where we have an existing base of proved reserves and producing wells, and in certain other major domestic producing basins where we believe significant upside potential exists. Our capital expenditures are generally discretionary and activity levels are determined by a number of factors, including oil and gas prices, availability of funds, quantity and character of identified investment projects, availability of service providers, and competition.
Basin's gross capital expenditures in 1999 totaled approximately $81.9 million. Our net capital expenditures in 1999 totaled approximately $71.2 million, after reflecting $10.7 million of proceeds from asset sales. Gulf of Mexico operations accounted for approximately 86% of our aggregate gross capital investments in 1999. These investments principally related to the ongoing development of seven properties with productive wells drilled in earlier periods, participation in the drilling of 21 wells, development costs related to the 15 of these wells that were successful, and costs related to identification and acquisition of exploratory prospects.
The remainder of our 1999 investments was associated with our onshore activities. These included participation in five exploratory wells, development costs related to two of these, exploitation of various Rocky Mountain properties, investments in seismic data and leaseholds for future exploration, and small proved property acquisitions.
Basin's initial exploration and development budget for 2000 provides for net capital investments of approximately $85 million. This budget primarily provides for:
- development of six Gulf of Mexico properties with one or more discovery wells yet to commence sustained production as of the end of 1999;
- participation in approximately six to eight net (15 to 20 gross) wells in the Gulf of Mexico, most of which are expected to be exploratory wells;
- participation in approximately three net (five gross) onshore exploration prospects;
- development of projected year 2000 exploratory discoveries;
- continued exploitation of our other offshore and onshore properties; and
- acquisitions of seismic data and exploratory leaseholds, both in the Gulf of Mexico and onshore.
Subject to realization of our projected production volumes and average oil and gas prices in 2000, we anticipate being able to fund the substantial majority of our planned capital investments this year with cash flow from operations. We plan to utilize current capacity under our revolving line of credit for the estimated residual.
We also intend to pursue acquisitions of properties with proved and probable reserves as an integral part of our overall business strategy. This strategy contemplates pursuing onshore proved properties to further establish core operating areas complementary to our Gulf of Mexico operations, and Gulf of Mexico properties with identified upside potential. We expect that these efforts will result in significant investment activity over time. However, we presently have not specifically allocated any portion of our 2000 budget for acquisitions of proved properties. If such a transaction is executed, it may require a re- allocation of funds from other planned activities and/or external financing, in addition to utilization of our revolving line of credit with our banks. In such instance, our overall capital budget for the year would likely be increased, potentially significantly.
The amount and allocation of future capital expenditures will depend on a number of factors that are not entirely within Basin's control or ability to forecast, including drilling results, scheduling of activities by other operators, availability of service providers, success in acquiring prospect leaseholds, and success in consummating acquisitions of proved properties. Basin's planned capital expenditures are also based on estimates regarding availability of capital that depend on assumptions and projections regarding production, oil and gas prices, and borrowing base re-determinations under our revolving line of credit. Due to these uncertainties, and other matters described under "Risk Factors" and "Summary--Forward-Looking Statements", actual capital expenditures may vary significantly from current expectations.
Year 2000 Readiness Disclosure and Statement
The forward-looking statements contained in the following Year 2000 discussion should be read in conjunction with our disclosures under the headings "Forward Looking Statements" and "Risk Factors" in this report.
Year 2000 issues result from the inability of many computer programs to accurately calculate, store or use a date subsequent to December 31, 1999. The date can be erroneously interpreted in a number of different ways; typically the year 2000 is interpreted as the year 1900. This could result in a system failure or miscalculations causing disruptions of or errors in operations. Systems potentially affected include not only information technology ("IT") systems -- computer systems controlling a company's accounting, land, operations, seismic processing, and other specialized functions -- but also non-IT systems controlled by embedded chips, which include many common and specialized machines and support systems. The effects of the Year 2000 problem can be exacerbated by the interdependence of computer and telecommunications systems in the United States and throughout the world. This interdependence can affect Basin and the parties with whom it does business.
Basin created an internal committee to assess its Year 2000 readiness and to lead its remediation efforts. At the direction of the committee, department heads and managers assessed and remediated Basin's IT and non-IT systems and communicated with Basin's business partners regarding the status of their assessment and remediation efforts. To date, Basin has not encountered any material Year 2000 problems with its IT and non-IT systems and has suffered no material adverse effects from this issue.
Through December 31, 1999, Basin spent less than $100,000 on its Year 2000 remediation efforts, none of which was capitalized. This figure does not include the cost of Year 2000-compliant software upgrades to various IT systems that Basin installed primarily for reasons unrelated to Year 2000 concerns, although the cost of such upgrades was not material. Basin did not retain consultants to advise it regarding its Year 2000 investigation and
remediation. Basin did not specifically track its internal costs of addressing the Year 2000 issue. However, management does not believe these internal costs were material.
Basin currently has no reason to believe that any Year 2000 compliance failures occurred or will occur with its systems or those of its significant business partners. However, there can be no assurance that all Year 2000 problems that could affect Basin through its business partners have been identified and corrected. Therefore, there can be no assurance that currently unknown Year 2000 issues will not materially impact Basin's results of operations or adversely affect its relationships with vendors, customers and other business partners in the year 2000.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company's exposure to interest rate risk and commodity price risk is discussed in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations under the headings "Operating Environment", "Liquidity and Capital Resources - Marketing and hedging transactions" and "Liquidity and Capital Resources - Credit facility". The Company has no direct exposure to foreign currency exchange rate risks or to any other market risks.
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 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 2000 Annual Meeting of Stockholders (the "Proxy Statement") to be filed with the Securities and Exchange Commission no later than April 30, 2000.
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
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 Consolidated 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, 1999 and 1998, 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, 1999. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the 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, 1999 and 1998, and the results of their operations and their cash flow for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Denver, Colorado, February 4, 2000.
BASIN EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
BASIN EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of these consolidated financial statements.
BASIN EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOW
The accompanying notes are an integral part of these consolidated financial statements.
BASIN EXPLORATION, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
For the Years Ended December 31, 1997, 1998 and 1999 (in thousands) - -------------------------------------------------------------------
The accompanying notes are an integral part of these consolidated financial statements.
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 operates its business and reports its operations as one business segment. Basin is engaged in the exploration, development and production of natural gas and crude oil. The Company's principal producing area is offshore in the Gulf of Mexico. Basin, as operator of jointly-owned oil and gas properties, sells a significant amount of such production to certain major customers (see Note 8), 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.
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. 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 and are not subject to amortization. Interest expense of $1,477,000 and $1,979,000 was capitalized to unproved property costs in accordance with SFAS 34 in the years ended December 31, 1998 and 1999, respectively. 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.
Under full cost accounting rules promulgated by the Securities and Exchange Commission, if net capitalized costs of oil and gas properties, less related deferred income taxes, exceed the full cost ceiling at the end of a fiscal quarter, the excess is charged to expense in that period. The full cost ceiling is calculated as the estimated present value of future net revenues from proved oil and gas reserves using a 10% discount factor and unescalated oil and gas prices as of the end of the period, or shortly thereafter, plus the book value of unproved oil and gas properties. Calculation of the full cost ceiling may be particularly sensitive to changes in expected production rates or the level of oil and gas prices, which may be volatile due to seasonal factors and other influences.
The Company recognized a $38,500,000 non-cash impairment charge ($30,750,000 after income tax effects) for the quarter ended December 31, 1998, based on a ceiling test calculation that utilized average realized prices of $10.23 per barrel of oil and $1.87 per Mcf of natural gas. A decline in prices could result in a requirement that the Company recognize additional impairment expense in a future period.
Furniture and Equipment - Furniture and equipment are depreciated over estimated - ----------------------- useful lives of four to seven years. Maintenance and repair costs are expensed as incurred.
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 commodity derivative - ------------------ contracts and fixed-price physical contracts to manage its exposure to oil and gas price volatility. Commodity derivatives contracts, which are placed with major financial institutions or other counterparties of high credit quality that the Company believes are minimal credit risks, may take the form of futures contracts, swaps or options. The reference prices of these commodity derivatives contracts are based upon crude oil and natural gas futures which have a high degree of historical correlation with actual prices received by the Company. The Company accounts for its commodity derivatives contracts using the hedge (deferral) method of accounting. Under this method, realized gains and losses from the Company's price risk management activities are recognized in oil and gas revenue when the associated production occurs and the resulting cash flows are reported as cash flows from operating activities. Gains and losses from commodity derivatives contracts that are closed before the hedged production occurs are deferred until the production month originally hedged. In the event of a loss of correlation between changes in oil and gas reference prices under a commodity derivatives contract and actual oil and gas prices, a gain or loss would be recognized currently to the extent the commodity derivatives contract did not offset changes in actual oil and gas prices.
The Company recognized reductions in oil and gas revenue of $144,000 and $383,000, respectively, under hedging agreements in 1997. The Company recognized increases in oil and gas revenue of $1,175,000 and $2,357,000, respectively, under hedging agreements in 1998. The Company recognized reductions in oil and gas revenue of $2,488,000 and $4,478,000, respectively, under hedging agreements in 1999.
As of February 4, 2000, the Company was a party to the following fixed price swap arrangements (one MMBtu approximates one Mcf of natural gas):
The Company also had sold call options for 10,000 MMBtu of natural gas per day for the period from January 2000 through December 2001 with an average strike price of $2.50 per MMBtu.
In accordance with SFAS 107, "Disclosures About Fair Value of Financial Instruments," the Company has estimated the fair value of its hedging arrangements at December 31, 1999, utilizing the then-applicable crude oil and natural gas price strips. While it is not the Company's intention to terminate any of the arrangements, it is estimated that the Company would have paid approximately $3,100,000 to terminate the then-existing arrangements on December 31, 1999. Due to the volatility of crude oil and natural gas prices, the fair market value may not be representative of the actual gain or loss that will ultimately be realized by the Company.
In June 1998, the Financial Accounting Standards Board issued SFAS 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS 133 establishes accounting and reporting standards requiring that, unless specific hedge accounting criteria are met, every derivative instrument, including certain derivative instruments embedded in other contracts, be recorded on the balance sheet as either an asset or liability measured at its fair market value and that changes in the derivative's fair market value be recognized currently in earnings. SFAS 133 is effective for the Company in 2001, but early adoption is allowed. The Company has not yet quantified the impacts of adopting SFAS 133 or determined the timing or method of adoption. However, SFAS 133 could increase volatility in earnings and other comprehensive income.
Earnings (Loss) Per Share - The Company adopted SFAS 128, "Earnings Per Share," - ------------------------- beginning with the fourth quarter of 1997. All prior period earnings per share have been restated to conform to the provisions of the statement. Basic earnings per share is computed based on the weighted average number of common shares outstanding. Diluted earnings per share is computed based on the weighted average number of common shares
outstanding adjusted for the incremental shares attributed to outstanding options and warrants to purchase common stock. Options to purchase 30,000 shares in 1997 and 50,000 shares in 1999 were not included in the computation of diluted earnings per share because the option exercise price was greater than the average market price of the Company's common stock. All options and warrants to purchase common shares were excluded from the computation of diluted earnings per share in 1998 because they were antidilutive as a result of the Company's net loss in that year.
In connection with the acquisition of Sterling Energy Corp. in November 1994, Basin 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. During 1997, 1998, and 1999, 48,523, 79,145 and 122,572 warrants were exercised, respectively. The remaining 49,760 warrants expired on December 31, 1999.
Comprehensive Income - There are no components of comprehensive income which - -------------------- have been excluded from net income and, therefore, no separate statement of comprehensive income has been presented.
(2) ACQUISITIONS OF OIL AND GAS PROPERTIES --------------------------------------
Basin consummated an acquisition of certain oil and gas properties from Midcon Offshore, Inc. on November 26, 1997. The purchase price was approximately $31,300,000, subject to normal post-closing adjustments. Basin was the high bidder at a bankruptcy court proceeding conducted to sell such assets, which were comprised principally of working interests in six federal lease blocks on the outer-continental shelf in the Gulf of Mexico, and the related platforms and production facilities. Approximately $5,000,000 of the purchase price was attributed to prospective drilling locations. The acquisition was accounted for as a purchase and, accordingly, the operating results of the acquired assets have been included in the Company's consolidated financial statements since the closing date.
(3) LONG-TERM DEBT
Effective January 1, 1999, and as subsequently amended, the Company entered into an Amended and Restated Credit Agreement (the "Credit Agreement") with its bank group. The Credit Agreement provides for borrowings of up to $150,000,000, with the interest rate on borrowings to be determined by reference to the prime rate or LIBOR, at the Company's election. A varying spread of 0% to 0.25% is added to the prime rate, or a spread of 0.75% to 1.5% is applied to LIBOR, based upon the Company's facility usage ratio. The Credit Agreement provides for borrowings to be revolving loans until November 30, 2002, at which time the outstanding balance will be converted into a four-year amortizing term loan unless the Credit Agreement has been amended to extend the revolving period. The borrowing base under the Credit Agreement, established at $90,000,000 as of December 1, 1999, is scheduled to be re-determined as of June 1, 2000 and generally at six- month intervals thereafter until converted into a 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. Pursuant to the agreement governing the Credit Agreement, substantially all of the Company's producing properties are subject to mortgages in favor of the banks and the Company's remaining properties are subject to a negative pledge. The weighted average interest rate on borrowings outstanding under the Credit Agreement at December 31, 1999 was 7.1%.
Outstanding debt at December 31, 1999 is payable as follows (in thousands):
2000 $ - 2001 - 2002 - 2003 8,500 2004 8,500 Thereafter 17,000 ------- $34,000 =======
(4) 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. At its discretion, the Company may also make additional contributions to the Plan. The Company expensed $183,000, $208,000 and $241,000 with respect to the Plan for the years ended December 31, 1997, 1998 and 1999, respectively.
Stock Plan - Under the Company's Equity Incentive Plan, officers, key employees, - ---------- consultants and directors of the Company are eligible to receive incentive stock options, non-qualified stock options, restricted stock and performance shares. The restricted stock and performance shares awarded under the plan entitle the grantee to the rights of a shareholder, including the right to receive any dividends and to vote such shares, but the shares are restricted as to sale, transfer or encumbrance. Options granted generally vest over three to four years, and expire after ten years. At December 31, 1999, approximately 1,896,000 shares were available for grant under the plan. Of this total, an aggregate of 1,467,000 shares of the Company's common stock are subject to prior issuances under such plan as of December 31, 1999, including 224,000 non-vested shares of restricted stock and performance shares and 1,243,000 outstanding stock options.
The following table summarizes stock options activity for the years presented:
Additional information regarding outstanding options at December 31, 1999 is as follows:
The Company granted 23,000 and 59,000 shares of restricted stock during 1997 and 1998, respectively. Related compensation expense was recognized in the amounts of approximately $120,000, $409,000 and $466,000 for the years ended December 31, 1997, 1998 and 1999, respectively. An additional 19,000 shares of restricted stock were granted in January 2000. Cumulatively through December 31, 1999, 79,000 shares of restricted stock had been forfeited, 64,000 shares were no longer subject to restriction, and 64,000 shares of restricted stock remained subject to forfeiture.
The Company granted 55,000, 50,000 and 55,000 performance shares during 1997, 1998 and 1999, respectively. In order for the performance shares to be released to the grantee, the Company must attain certain performance goals by the end of a three-year performance cycle which begins with the year of award. Expense is recognized based on vesting schedules, projections of performance, and changes in the price of the Company's common stock during the applicable vesting period. Related compensation expense was recognized in the amounts of $447,000, $367,000 and $1,593,000, for the years ended December 31, 1997, 1998 and 1999, respectively.
In October 1995, the Financial Accounting Standards Board issued SFAS 123, "Accounting for Stock-Based Compensation." SFAS 123 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.
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-Scholes option- pricing model with the following weighted-average assumptions and effects:
(5) 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 from third parties under various noncancelable lease arrangements. The following is a schedule of future minimum lease obligations under these leases at December 31, 1999:
Future minimum lease obligations (in thousands)
2000 $ 679 2001 788 2002 894 2003 951 2004 976 Thereafter 106 ------ $4,394 ======
Payments related to such lease obligations were approximately $990,000, $1,096,000 and $591,000 for the years ended December 31, 1997, 1998 and 1999, respectively. The Company formerly subleased office space to third parties, the related receipts were $502,000, $506,000 and $186,000 in the years ended December 31, 1997, 1998 and 1999.
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, are likely to have a material adverse effect on the Company's financial condition, liquidity or results of operations.
(6) INCOME TAXES ------------
The components of the provision (benefit) for income taxes are as follows:
Reconciliations of income tax provisions (benefits) 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:
(7) RELATED PARTY TRANSACTIONS --------------------------
Prior to its initial public offering, the Company advanced $559,000 to its principal stockholder at an annual interest rate of 9 percent. Pursuant to the terms of the note, the principal stockholder elected to surrender 28,217 shares of Basin's common stock to the Company in the fourth quarter of 1997 to settle the note. The surrendered shares are reflected as treasury stock in the accompanying statement of changes in stockholders' equity.
(8) OIL AND GAS ACTIVITIES ----------------------
The Company's oil and gas operations are conducted solely 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:
(a) less than ten percent
Costs Incurred - Costs incurred in oil and gas operations and related depletion - -------------- per equivalent unit-of-production were as follows:
/1/ Excludes $1,113,000, $150,000 and $9,995,000 of costs recouped through the resale of partial interests in prospects to industry partners in 1997, 1998 and 1999, respectively.
Costs Not Being Amortized - Oil and gas property costs not being amortized at - ------------------------- December 31, 1999, consisted of $26,567,000 of leasehold and seismic costs, of which $2,075,000, $1,607,000, $10,553,000 and $12,332,000 were incurred in 1996, 1997, 1998 and 1999, respectively. The Company anticipates that substantially all unevaluated costs will be classified as evaluated costs within three years.
UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION
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 estimate. Accordingly, reserve estimates will vary 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, and future prices, 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: $16.34 per barrel of oil and $2.32 per Mcf of gas at December 31, 1997; $10.31 per barrel of oil and $1.99 per Mcf of gas at December 31, 1998; and $24.39 per barrel of oil and $2.32 per Mcf of gas at December 31, 1999.
Estimated reserve quantities and standardized measures set forth herein utilize such prices (which were based on prevailing sales prices at the time) held constant in future periods and a 10% discount rate.
All of the Company's reserves are located onshore or offshore in the United States. The following tables include estimates for the Company's onshore and offshore reserves combined. Estimates of onshore reserves were prepared by the Company's engineers and audited by Netherland, Sewell & Associates, Inc. at December 31, 1996 and 1997 and by Ryder Scott Company Petroleum Engineers at December 31, 1998 and 1999. Estimates of offshore reserves were either prepared by Ryder Scott Company Petroleum Engineers, or prepared by the Company's engineers and audited by Ryder Scott Company Petroleum Engineers.
ANALYSES OF CHANGES IN PROVED RESERVES
The following table sets forth information regarding the Company's estimated net total proved and proved developed oil and gas reserve quantities:
STANDARDIZED MEASURE
The following table presents the standardized measure of discounted future net cash flows related to proved oil and gas reserves:
/1/ Total future net cash flows before income taxes discounted at 10% per annum are $160,230,000, $164,485,000 and $269,303,000 as of December 31, 1997, 1998 and 1999, respectively.
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:
UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA
Gross profit from operations is comprised of oil and gas sales less lease operating expenses and production taxes. The net loss for the fourth quarter of 1998 includes a property impairment of $38,500,000. Earnings (loss) per share is computed independently for each of the quarters presented and, therefore, may not sum to the totals for the year.
(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, 1994/4/ 2.2 Plan of Merger between Basin Sterling, Inc. and Basin Exploration, Inc. dated November 22, 1994/4/ 2.3 Plan of Merger between Basin Operating Company and Basin Exploration, Inc. dated December 14, 1994./5/ 3.1 Restated Certificate of Incorporation of Basin./2/ 3.2 Restated Bylaws of Basin, as amended February 23, 2000./1/ 4.1 Common Stock Certificate of Basin./2/ 10.1 Equity Incentive Plan as amended May 12, 1999./11/ 10.2 Employment Agreement dated March 31, 1992 by and between Basin Exploration, Inc. and Michael S. Smith./3/ 10.3 Gulf Coast Geoscientist Overriding Royalty Interest Plan as amended November 10, 1999./12/ 10.4 Onshore Geoscientist Overriding Royalty Interest Plan dated August 24, 1999./12/ 10.5 Form of Rights Agreement dated as of February 24, 1996, between Basin Exploration, Inc. and Corporate Stock Transfer, Inc. as Rights Agent./6/ 10.6 Performance Shares Plan approved February 4, 1997./8/ 10.7 Change of Control Employment Agreement dated October 13, 1995 between Basin Exploration, Inc. and Howard L. Boigon./7/ 10.8 Amendment to Change of Control Employment Agreement dated June 2, 1999 between Basin Exploration, Inc. and Howard L. Boigon./11/ 10.9 Change of Control Agreement dated August 28, 1997 between Basin Exploration, Inc. and Samuel D. Winegrad./11/ 10.10 Change of Control Agreement dated August 1, 1997 between Basin Exploration, Inc. and Neil L. Stenbuck./12/ 10.11 Employment Agreement dated February 1, 1999, between Basin Exploration, Inc. and David A. Pustka./10/ 10.12 Change of Control Agreement dated March 24, 1999 between Basin Exploration, Inc. and Thomas J. Corley./1/ 10.13 Employment Agreement dated January 28, 1999, between Basin Exploration, Inc. and Patrick A. Jackson./10/ 10.14 Change of Control Agreement dated May 12, 1999 between Basin Exploration, Inc. and Dalton F. Polasek./1/ 10.15 Order of the United States Bankruptcy Court for the Southern District of Texas Corpus Christi Division, dated November 18, 1997, with exhibits, including the Agreement of Purchase and Sale./9/ 10.16 Amended and Restated Credit Agreement dated January 1, 1999 among the Company and NationsBank, N.A., U.S. Bank National Association and Union Bank of California, N.A./10/ 10.17 First Amendment of Amended and Restated Credit Agreement dated July 1, 1999 among the Company, NationsBank, N.A., U.S. Bank National Association and Union Bank of California, N.A./11/ 10.18 Second Amendment of Amended and Restated Credit Agreement dated October 15, 1999 among the Company and U.S. Bank National Association, Union Bank of California, Toronto Dominion (Texas), Inc. and Bank of America National Trust and Savings Association./12/ 10.19 Third Amendment of Amended and Restated Credit Agreement dated December 1, 1999, among Basin Exploration, Inc. and U.S. Bank National Association, Union Bank of California, Toronto Dominion (Texas), Inc. and Bank of America National Trust and Savings Association./12/ 21 Subsidiaries/1/ 23.1 Consent of Arthur Andersen LLP/1/ 23.2 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 Form 8-K filed on December 10, 1994, and incorporated herein by reference. /5/ Filed as an Exhibit to Form 10-K filed on March 28, 1995, and incorporated herein by reference. /6/ Filed as an Exhibit to Form 8-K filed on February 26, 1996, and incorporated herein by reference. /7/ Filed as an Exhibit to Form 10-K filed on March 28, 1996, and incorporated herein by reference. /8/ Filed as an Exhibit to Form 10-K filed on March 31, 1997, and incorporated herein by reference. /9/ Filed as an Exhibit to Form 8-K filed on December 11, 1997, and incorporated herein by reference. /10/ Filed as an Exhibit to Form 10-K filed on March 30, 1999, and incorporated herein by reference. /11/ Filed as an Exhibit to Form 10-Q filed on August 16, 1999, and incorporated herein by reference. /12/ Filed as an Exhibit to Form 10-Q filed on November 15, 1999 and incorporated herein by reference.
+ Confidential treatment has been granted for portions of these Exhibits.
(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 27, 2000 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.