ITEM 1. BUSINESS.
GENERAL
Basin Exploration, Inc. ("Basin" or the "Company") is engaged in the exploration, acquisition, development and exploitation of oil and gas properties. The Company's properties are located primarily offshore Louisiana and Texas in the shallow waters of the Gulf of Mexico and in the Powder River and Green River Basins of Wyoming. As of December 31, 1998, the Company's estimated net proved reserves were 127.5 Bcf of natural gas and 8.7 MMBbl of oil, or 179.5 Bcfe, with an aggregate pre-tax present value of future net revenues of $164.5 million, using 1998 year-end prices held constant and a 10% discount rate.
In 1996, the Company changed its primary focus from the Rocky Mountain region to the shallow waters of the Gulf of Mexico. To implement this change in focus, between late-1995 and mid-1996 the Company added senior management and technical personnel, including geoscientists and petroleum engineers with extensive experience in the Gulf of Mexico, and strengthened its balance sheet by selling its D-J Basin properties in Colorado for $123.5 million. The Company's divestment of its D-J Basin assets and its commitment to Gulf of Mexico exploration significantly changed the character and risk profile of its investment activities.
Since commencing operations in the Gulf of Mexico in 1996, through the end of 1998, the Company has participated in drilling 31 Gulf of Mexico wells, including 20 that found apparent commercial hydrocarbons. The Company has operated 22 of the 31 wells in which it has participated and has retained working interests averaging approximately 54% at the time of drilling. As of year-end 1998, the Company had assembled a Gulf of Mexico leasehold position totaling 218,718 gross acres, or 149,430 net acres, with more than 40 identified exploration prospects supported by the Company's interpretations of three-dimensional ("3-D") seismic data. See "PROPERTIES - Present Activities" for information about certain developments subsequent to December 31, 1998.
During 1998, the Company invested $106.7 million in oil and gas properties, of which approximately 96% related to activities in the Gulf of Mexico. Expenditures related to the Gulf of Mexico were primarily for drilling 17 exploratory wells, 11 of which found apparent commercial hydrocarbons, completion and development activities related to these discoveries and discoveries made in the prior year, and for acquisitions of seismic data and exploratory leaseholds. Other investments made in 1998 were primarily for exploitation and development of the Company's Rocky Mountain oil and gas properties, and for exploration activities in the Rocky Mountain area. Capital expenditures in 1998, and in 1997 when oil and gas investments totaled $105.6 million, were significantly greater than in prior years and resulted in a 133% increase in estimated proved oil and gas reserve quantities over the two-year period and a substantial increase in undeveloped Gulf of Mexico leaseholds. As a result of the large portion of such capital expenditures that related to Gulf of Mexico activities, Gulf of Mexico assets accounted for 75% of the Company's proved reserves at the end of 1998, compared to 9% at the beginning of 1997, and properties in the Gulf of Mexico contributed 86% of fourth quarter 1998 average daily net production of 65.9 MMcfe, versus 0% of the Company's average daily net production of 11.2 MMcfe as recently as the second quarter of 1997. Since initiating its Gulf of Mexico production from a single property in August 1997, the Company had expanded its production base in the area to 14 properties by the end of 1998. Four additional properties with proved reserves were under development for initial production at that date.
The Company's capital expenditures in 1998 were funded primarily with cash flow from operations, which totaled $33.7 million before changes in working capital, and bank debt, which increased from $11 million at the beginning of 1998 to $80 million at the close of the year.
During 1998 the Company produced a total of 22.0 Bcfe, or 60.2 MMcfe per day, compared to 1997 production of 8.7 Bcfe, or 23.7 MMcfe per day. This 154% increase in production combined with a 22% decline in weighted-average prices received to generate a 99% increase in revenues. The revenue increase resulted in a 120% increase in cash flow from operations before changes in working capital, from $15.3 million in 1997 to $33.7 million in 1998. The Company's production in 1998 was comprised of 80% natural gas and 20% oil.
The increase in production from 1997 to 1998 was principally attributable to reserves additions made in 1997. The Company did not make any significant acquisitions of producing properties in 1998 and wells drilled during 1998 did not account for a substantial portion of 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.
Reflecting low oil and gas prices at the end of 1998, Basin recorded a $30.8 million after-tax, non-cash charge to reduce the carrying value of its oil and gas properties. As a result, the Company reported a net loss for the year of $28.5 million. Without the non-recurring charge, the Company would have reported net income for the year of $2.3 million.
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
Basin's goals are to generate per-share growth in reserves, production, earnings and cash flow through exploration, acquisition and development of oil and gas properties. The Company seeks to implement these goals through the following strategies:
EXPLORE IN THE SHALLOW WATERS OF THE GULF OF MEXICO. Basin's exploration activities are currently focused primarily in the shallow waters on the Outer Continental Shelf ("OCS") of the Gulf of Mexico. The Company believes that this region has significant remaining undiscovered reserves and that the combination of substantial existing infrastructure and the effectiveness of 3-D seismic data will reduce exploration risk and enhance project economics.
CAPITALIZE ON TECHNICAL EXPERTISE. Basin has assembled a team of geoscientists and petroleum engineers with substantial experience and expertise relating to operations in the Gulf of Mexico to generate prospects and evaluate acquisition opportunities in that region. Basin has also added senior management and technical personnel with substantial operating experience outside of the Gulf of Mexico and intends to utilize this in-house capability in conjunction with consultants to identify and evaluate growth opportunities in selected onshore areas, and to pursue such opportunities through acquisitions of properties or through exploration ventures.
UTILIZE ADVANCED TECHNOLOGY. Basin makes extensive use of advanced technologies, including 3-D seismic and computer-aided exploration and exploitation ("CAEX") performed on eight Landmark workstations, to better define drilling prospects and exploitation opportunities. Basin has licensed more than 375,000 miles of conventional 2-D seismic data and approximately 600 lease blocks of 3-D seismic data covering portions of the Gulf of Mexico.
BALANCE SIZE AND RISK PROFILE OF EXPLORATION TARGETS. Basin seeks to conduct a drilling program that is balanced between large-target exploration prospects relative to the Company's existing reserve base and lower-risk, smaller exploration prospects, generally near existing infrastructure, which reduces development costs and expedites commencement of production. This balance is intended to mitigate risk while still gaining exposure to meaningful growth in reserves and production.
GENERATE PROSPECTS INTERNALLY. Basin's team of geoscientists internally generates prospects using the Company's technical data bases and workstations. The Company believes that internally generating prospects will enable it to retain large working interests and operating control and to either bring in partners on a promoted basis or swap for interests in third-party generated prospects. Although the Company primarily relies on internal generating activities for prospect leads, the Company also evaluates outside-generated opportunities. Several outside-generated prospects have been obtained in conjunction with the originating party's participation in prospects generated by the Company. Basin focuses its current prospect generating activities primarily offshore Louisiana in the near-shore Miocene trends, integrating subsurface geology with a regional grid of 3-D seismic data. The Miocene trend is characterized by geologic structures with favorable reservoir parameters and conditions where subtle hydrocarbon indicators are sometimes apparent.
OPERATE CORE PROPERTIES. At December 31, 1998, Basin served as operator for properties accounting for more than 65% of the Company's proved reserve quantities. Serving as operator allows the Company to exert greater control
over the cost, timing and character of its exploration, development and production activities. Although the Company favors acting as operator, it does participate in outside-operated projects that it deems attractive.
PURSUE SELECTIVE ACQUISITIONS. Basin actively seeks to acquire interests in proved oil and gas properties with exploration, exploitation or development potential to augment operations in its core areas and to establish positions in new areas. Generally, the Company focuses on acquisition opportunities where it believes it can enhance the value of the acquired assets through one or more of the following means: (i) exploratory drilling; (ii) development drilling; (iii) workovers; (iv) recompletions; (v) fracture stimulation; (vi) secondary recovery operations; and (vii) cost reductions.
MAINTAIN FINANCIAL FLEXIBILITY. Basin seeks to maintain financial flexibility in order to be able to take advantage of identified investment opportunities. Since the Company anticipates that its 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
The Company's gas and natural gas liquids from Gulf of Mexico properties are sold under short-term contracts at market prices to various gas purchasers. These sales may involve delivery of gas to onshore points under the Company's firm and interruptible transportation agreements or sales at the wellhead. Oil from the Company's Gulf of Mexico properties is sold under short-term contracts at market prices. The Company enters into liquids transportation and separation agreements to deliver its crude oil and condensate onshore.
Because of the well-developed transportation infrastructure and the relatively large number of active oil and gas purchasers in the Gulf Coast area, including in the Gulf of Mexico where the Company conducts exploration and acquisition activities, the Company does not anticipate that it will have difficulty in marketing its production in this region at prevailing spot market prices.
The majority of the Company's gas and natural gas liquids from fields in the Rocky Mountain region are sold under marketing arrangements where prices received are responsive to changes in regional spot markets. These include short-term contracts under which gas is 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.
KN Gas Gathering ("KNGG") purchases virtually all of the Company's Powder River Basin gas and natural gas liquids from the Company's operated wells at netback prices similar to other percentage-of-proceeds contracts in the area. The KNGG contract does not have minimum take provisions and thus the Company's realization of proceeds depends on KNGG's ability to find a market for the Company's gas and natural gas liquids. If KNGG were to cease purchasing the Company's gas, the Company believes that it could sell its gas and natural gas liquids to other purchasers and processors in the area, although such sales would require capital expenditures for gathering system modification and might not be on terms as favorable as those characterizing the KNGG sales. The Company does not believe that the loss of KNGG as a purchaser would have a material adverse effect on the Company.
Oil from the Company's Rocky Mountain properties is generally sold under term contracts that yield a premium over local posted prices.
Demand for natural gas is highly seasonal, with demand generally higher in the colder winter months and in hot summer months. As a result, the price received for spot market natural gas may vary significantly between seasonal periods. To date, the Company generally has been able to sell its available spot market natural gas at prevailing spot market prices, and the volumes sold have not materially fluctuated seasonally. There is no assurance, however, that the Company 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. The Company anticipates that such markets will continue to be volatile in the foreseeable future. Oil and gas price fluctuations have a significant impact on the Company's business since virtually all of the Company's operating revenues are ordinarily derived from sales of its oil and gas production. The Company believes that the loss of one or more of its current oil or natural gas spot purchasers would not have a material adverse effect on the Company's business because any individual purchaser should be readily replaceable by another purchaser who could be expected to pay approximately the same sales price.
Basin periodically enters into oil and gas price hedging agreements as conditions are deemed to warrant. Such transactions affecting the three year period ended December 31, 1998, or currently in effect with respect to subsequent periods, are described below under "Management's Discussion and Analysis of Financial Condition and Results Of Operations - Liquidity and Capital Resources" and in the Notes to Consolidated Financial Statements.
COMPETITION
Competition in the oil and gas industry is intense, particularly with respect to the acquisition of producing properties and proved undeveloped acreage and the acquisition of interests in offshore exploration prospects in the Gulf of Mexico. Major and independent oil and gas companies, as well as individuals and drilling programs, actively bid for desirable oil and gas properties, as well as for the equipment and labor required to operate and develop such properties. A number of Basin's competitors have financial resources and exploration and development budgets that are substantially greater than those of Basin, which may adversely affect the Company's ability to compete successfully. In addition, many of the Company's larger competitors may be better able to respond to factors that affect the demand for oil and natural gas production such as changes in worldwide oil and natural gas prices and levels of production, the cost and availability of alternative fuels, and the application of government regulations. The Company commenced operations in the Gulf of Mexico area during 1996, where it had not previously been active. Competition from major and large independent oil and gas companies is significantly greater in this area than in the Rocky Mountain region, where the Company had conducted all of its previous operations.
RISK FACTORS
In addition to the other information set forth elsewhere in this Form 10-K, you should carefully consider the following factors relating to Basin when evaluating the Company.
OIL AND GAS PRICES, AND HEDGING - OIL AND GAS PRICES ARE CURRENTLY LOW AND DEPEND ON FACTORS OUT OF OUR CONTROL. LOW PRICES COULD HAVE A MATERIAL ADVERSE IMPACT ON OUR BUSINESS. WE MAY HEDGE SOME OF OUR PRODUCTION TO REDUCE PRICE RISK, BUT THAT MAY ALSO REDUCE OUR GAIN FROM PRICE INCREASES.
Prices for oil and natural gas fluctuate widely and have declined significantly over the past year. The weighted average market prices being received by Basin for natural gas decreased from approximately $2.32 per Mcf at December 31, 1997 to $1.99 per Mcf at December 31, 1998. During the same twelve-month period, average crude oil prices received by Basin decreased from $16.34 per barrel to $10.31 per barrel.
Natural gas prices affect Basin more than oil prices, because most of our production and reserves are natural gas. At December 31, 1998, 71% of our estimated proved reserves consisted of natural gas on an Mcfe basis, and in 1998 approximately 80% of our total production consisted of natural gas.
Basin's revenues, profitability and future rate of growth substantially depend on prevailing prices for oil, gas and natural 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 re-determination based on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that Basin can produce economically. As an example, our estimated proved reserves at December 31, 1998 were lower than they would have been had prices not declined from year-end 1997.
We cannot predict future oil and natural gas prices and prices may decline further. Among the factors that can cause this fluctuation are:
- relatively minor changes in the supply of and demand for oil and natural gas;
- market uncertainty;
- the level of consumer product demand;
- weather;
- domestic and foreign governmental regulations;
- the price and availability of alternative fuels;
- political conditions in the Middle East;
- the foreign supply of oil and natural gas;
- the price of oil and gas imports; and
- economic conditions in the United States and in other countries.
We periodically enter into energy price swap agreements and other financial arrangements to attempt to mitigate the effects of oil and natural gas price fluctuations. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," and Note 1 of Notes to Consolidated Financial Statements for a description of our recent hedging activity. Such arrangements are subject to a number of risks. If our reserves are not produced at the rates we estimated, we would be required to satisfy our 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 anticipated profit margins and our ability to manage price risk. 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. Furthermore, hedging contracts limit the benefits we would realize if actual prices rise above the contract prices.
REPLACEMENT OF RESERVES - WE MAY NOT BE ABLE TO REPLACE RESERVES AND THE FAILURE TO DO SO WOULD ADVERSELY AFFECT THE COMPANY'S LIQUIDITY AND OPERATIONS.
Unless Basin conducts successful development, exploitation or exploration activities or acquires properties containing proved reserves, the proved reserves of Basin will decline as reserves are produced. Decline rates depend on a number of factors, including drilling density, completion procedures, and reservoir characteristics. They vary from generally steep declines of production from reservoirs in the Gulf of Mexico, where Basin has most of its production, to relatively slow declines of long-lived fields in the Rocky Mountain region, where our other properties are located. The market for acquiring proved reserves is extremely competitive, and we may not be able to buy reserves for development and exploitation at reasonable prices. Basin's drilling operations may be unsuccessful or 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. Because of low oil and gas prices, we have reduced our projected capital expenditure budget from the level of the past two years. This may result in drilling fewer wells and could reduce our reserves growth below that of prior years. We cannot assure you that our future acquisition, development, exploitation and exploration activities will result in reserves added at acceptable costs.
ACQUISITION RISKS - ACQUIRED PROPERTIES 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. SUBSTANTIAL ACQUISITIONS COULD REQUIRE SIGNIFICANT CAPITAL INFUSIONS AND COULD CHANGE BASIN'S RISK AND PROPERTY PROFILE.
Our recent growth is due in part to acquisitions of producing properties. The successful acquisition of producing properties requires assessments of many factors. These include recoverable reserves, future oil and gas
prices, operating costs, future development costs, and potential environmental and other liabilities. These assessments are inherently inexact and their accuracy uncertain. In connection with such assessments, we review the targeted properties in a manner we believe is prudent and consistent with industry practice. However, such a review will not reveal all existing or potential problems or permit a buyer to become familiar enough with the properties to assess fully their deficiencies and capabilities. We may not inspect every well, platform or pipeline. Structural and environmental problems, such as pipeline corrosion or groundwater contamination, are not necessarily observable even when an inspection is made. We may not be able to obtain contractual indemnities from the seller for pre-closing liabilities. 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.
Basin constantly evaluates acquisition and joint venture opportunities and frequently engages in bidding and negotiation for acquisitions, many of which are substantial. If successful in this process, Basin may need to alter or increase its 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 Basin's risk profile. Additionally, significant acquisitions or joint ventures can change the character of the operations and business of Basin depending upon the character of the properties, which may be substantially different in operating or geological characteristics or geographic location than existing properties. We cannot assure you that Basin will be successful in the acquisition or development of any material property interests.
EXPLORATION RISKS - BASIN'S GROWTH STRATEGY SUBSTANTIALLY DEPENDS ON THE SUCCESS OF ITS EXPLORATION, A HIGH-RISK ACTIVITY. BASIN USES 3-D SEISMIC AND OTHER ADVANCED TECHNOLOGIES TO MITIGATE EXPLORATION RISK, BUT SUCH TECHNOLOGIES ARE EXPENSIVE, REQUIRE EXPERIENCED PERSONNEL, AND CANNOT ELIMINATE EXPLORATION RISK.
Basin has spent a large portion of its capital budget on exploration in recent years and anticipates continuing to do so in the future. Exploration activities are substantially more risky than development or exploitation activities. We use 3-D seismic data and other advanced technologies to reduce our risk, but exploratory drilling remains a speculative activity. Even when extensively utilized 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. In addition, the use of 3-D seismic data and certain other technologies requires greater pre-drilling expenditures than traditional drilling strategies and 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. Basin had conducted no previous operations in the Gulf of Mexico prior to opening its regional office in late 1995 in Houston, Texas. This operating area is highly competitive and Basin's success there will depend on its ability to attract and retain experienced geoscientists and other professional staff. Basin's Houston office currently has ten geoscientists and petroleum engineers plus two engineering consultants, all of whom are experienced in Gulf Coast operations. Loss of these experienced personnel could have a material adverse impact on Basin's ability to compete in this area.
FUTURE CAPITAL REQUIREMENTS - BASIN'S CAPITAL EXPENDITURES HAVE GENERALLY EXCEEDED ITS CASH FLOW. IF WE CANNOT CONTINUE TO ACCESS CAPITAL FROM EXTERNAL SOURCES, WE WILL HAVE LESS CAPABILITY TO GROW OUR RESERVES AND PRODUCTION.
We need substantial capital to develop and explore our properties and acquire additional properties. We will use cash flows from operations to fund these expenditures to the extent available. However, generally our capital investments have exceeded our cash flows. Historically we have addressed our long-term liquidity needs through bank borrowings and the issuance of equity securities. We continue to examine the following alternate sources of long-term capital:
- traditional reserve-base borrowings or the issuance of long-term debt;
- the sale of common stock, preferred stock or other equity securities;
- the issuance of nonrecourse production-based financing or net profits interests;
- sales of non-strategic properties;
- sales of interests in prospects and technical information; and
- joint ventures.
Basin's ability to access additional capital will depend on 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. 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."
EFFECTS OF LEVERAGE - OUR DEBT COULD REDUCE OUR FINANCIAL FLEXIBILITY AND UNDER CERTAIN CIRCUMSTANCES COULD REQUIRE PRINCIPAL REDUCTIONS THAT WE ARE UNABLE TO MAKE.
We have significant indebtedness. At year-end 1998, the amount of our long-term debt was $80 million, and we had $30 million available to draw down under our credit agreement with our banks. Our working capital deficit was $13.2 million at year-end 1998, leaving a net total of $16.8 million of unutilized credit capacity. Under our credit agreement, our borrowing base is re-determined at least semi-annually by our banks, 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.
There are several effects of this leverage on Basin:
- it may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general corporate purposes;
- a portion of our cash flow from operations must be dedicated to the payment of interest on our existing indebtedness, which will reduce the availability of our cash flow to fund working capital, capital expenditures and other corporate needs;
- our credit agreement contains restrictive covenants that limit our ability to engage in certain transactions;
- our borrowings under our bank credit facility are at floating rates, which may make us vulnerable to increases in interest rates;
- our credit agreement requires us to make regular interest payments, and at the end of the revolving period to make scheduled principal payments. In addition, we must make principal payments if our outstanding borrowings exceed our borrowing base, as it may periodically be re-determined by the banks. If we default in such payments, which may be made in installments over six months, our lenders would be entitled to accelerate the payment of all amounts owed under our credit facility. We cannot assure you that future borrowings or debt or equity financing will be available to pay or refinance such required obligations. Our failure to remedy such a default could result in a foreclosure by the banks of their mortgages on the properties containing our proved reserves.
CEILING LIMITATION WRITE-DOWNS
We use the full cost method of accounting to report our operations for oil and gas properties. Basin capitalizes 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" which is based upon 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 impact cash flow from operating activities, but it does reduce the book value of our shareholders' equity. 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 Basin has substantial downward adjustments to its estimated proved reserves. We review the carrying value of our properties quarterly, based on prices in effect as of the end of each fiscal quarter (or the time of reporting results). We may not reverse
any such write-downs even if prices increase in subsequent periods, but such write-downs do result in reduced subsequent charges for depreciation, depletion and amortization. Primarily because of weak oil and gas prices, Basin recorded a ceiling limitation write-down for the fourth quarter of 1998 in the amount of $30.8 million ($38.5 million pre-tax). We cannot assure you that we will not have another ceiling limitation write-down in a future period if commodity prices continue to weaken.
MARKETING OF PRODUCTION; SEASONALITY
The marketability of Basin's production depends in substantial part on the availability and capacity of gathering systems, pipelines, and processing facilities owned and operated by third parties. Federal and state regulation of production and transportation, general economic conditions, and changes in supply and demand all could adversely affect Basin's ability to market its production. Demand for natural gas is highly seasonal, with demand generally higher in the colder winter months and in the hot summer months. As a result, the price and marketability of our spot market natural gas may vary significantly between seasonal periods. If market factors dramatically changed, the financial impact on Basin could be substantial. The availability of markets is beyond our control.
CONCENTRATION OF VALUE
At December 31, 1998, over 80% of our daily production was from 12 wells on nine platforms in the Gulf of Mexico. If mechanical problems, storms, or other events curtailed a substantial portion of this production, Basin's cash flow would be materially adversely affected. UNCERTAINTY OF ESTIMATES OF OIL AND GAS RESERVES - RESERVE ESTIMATES ARE INHERENTLY UNCERTAIN AND DEPEND ON MANY ASSUMPTIONS WHICH MAY TURN OUT TO BE UNTRUE. This Form 10-K contains estimates of our proved oil and gas reserves and the estimated future net revenues from such reserves. Basin's historical proved reserve information incorporated by reference in this Form 10-K represents only estimates based on reports prepared in part by independent petroleum engineers and in part by internal Basin engineers. The process of estimating oil and gas reserves is complex and inherently uncertain. It requires various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Production rates and timing of development expenditures must be projected. Available geological, geophysical, production and engineering data must be analyzed, 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, and estimates of 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 those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth in this Form 10-K. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control. Our reserves at December 31, 1998 were lower than they would have been if oil and gas prices in effect at year-end 1997 were still in effect.
At December 31, 1998, approximately 31% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling operations. The reserve data assumes that we will make these expenditures. Although we have estimated our reserves and the costs associated with developing them in accordance with industry standards, we cannot assure you that the estimated costs are accurate, that development will occur as scheduled or that the results will be as estimated.
You should not assume that the present value of future net revenues referred to in this Form 10-k is the current market value of our estimated oil and gas reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of 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. Recent significant declines in oil and gas prices have reduced Basin's present value of future net revenues. See "Oil and Gas Prices; Hedging." Any material changes in aggregate consumption by gas purchasers or in governmental regulations or taxation could also affect actual future net cash flows. The timing of development of oil and gas properties will affect both the production and the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily an appropriate discount factor for estimating the value of oil and gas reserves. The effective interest rate at various times and the risk associated with Basin, the properties, or the oil and gas industry in general will affect the reasonableness of the 10% discount factor.
FLUCTUATIONS IN QUARTERLY RESULTS - THESE FLUCTUATIONS CAN CAUSE SUDDEN CHANGES IN THE MARKET PRICE OF OUR COMMON STOCK.
Basin's 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 can be expected to decline when our quarterly results decline or when announcements of adverse events regarding the Company or the industry are made.
OPERATING HAZARDS - THE OIL AND GAS BUSINESS INVOLVES MANY OPERATING RISKS WHICH 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. These include the risk of 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. The occurrence of any of these events could result in substantial losses to Basin. Losses can occur from 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. These problems can affect wellbores, platforms, gathering systems and processing facilities, and any significant problems related to those facilities could adversely affect Basin's ability to conduct its operations. Moreover, 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 possibly interrupt production. In addition, Basin may be liable for environmental damages caused by previous owners of properties it purchases. As a result, Basin 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 Basin's properties.
In accordance with industry practice, Basin maintains insurance against some, but not all, potential risks. Basin's coverages include, but are 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 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.
ENVIRONMENTAL REGULATION - OIL AND GAS OPERATIONS ARE SUBJECT TO EXTENSIVE ENVIRONMENTAL REGULATION WHICH CAN INCREASE COSTS, CREATE MAJOR LIABILITIES, OR PRECLUDE OPERATIONS.
Oil and gas operations are subject to extensive regulation under federal, state and local environmental laws. Generally, regulation relates to water and air pollution control and solid waste management, permitting, or restrictions on operations in environmentally sensitive areas, such as coastal zones, wetlands, and wildlife habitat. We have not performed environmental assessments on all of our acquired properties. To date, our expenditures for environmental control facilities and for remediation have not been significant in relation to our results of operations. We believe, however, that the trend toward stricter standards in environmental legislation and regulation is likely to continue. Offshore operations are subject to more extensive governmental regulation, including regulation that may impose absolute liability for environmental damage and allow interruption or termination of business activities by government
authorities. The Oil Pollution Act of 1990 also requires proof of financial responsibility to cover costs of potential oil spills; the amount of such required coverage ranges from $35 million to $150 million based on federal risk assessment. From time to time, legislation has been introduced in Congress which would reclassify oil and gas production wastes as "hazardous waste" under the Resource Conservation and Recovery Act. If such legislation were to pass, it could have a significant adverse impact on our operating costs. Initiatives regulating the disposal of exploration and production waste are also pending or have been enacted in states in which Basin conducts operations, and these initiatives could have a similar impact on Basin.
GOVERNMENTAL REGULATION - OIL AND GAS OPERATIONS ARE SUBJECT TO EXTENSIVE 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 governmental regulation. Areas covered include operations permits, drilling, plugging and reclamation bonds, operational practices and reporting, the spacing of wells, unitization and pooling of properties, taxation and environmental protection. The Minerals Management Service of the United States Department of the Interior has proposed regulations for valuation of crude oil and natural gas produced from federal leases, including offshore leases, that could require payment of royalties on the basis of indices or benchmarks that may not reflect actual prices Basin receives for its production. The Federal Energy Regulatory Commission has promulgated major regulatory initiatives over the past several years which have had a significant impact on natural gas pricing and natural gas pipeline operations, services and rates. Those changes have significantly altered the marketing of natural gas. Although the purpose of these changes is generally to enhance competition in natural gas marketing, the effect of these changes on our ability to market our gas at reasonable prices is uncertain. Regulatory agencies in the past have imposed price controls and limitations on production by restricting the rate of flow of oil and gas wells below actual production capacity in order to conserve supplies of oil and gas. 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. The Minerals Management Service may suspend or terminate operations for violation of its rules. Any such suspension or termination could materially and adversely affect Basin's financial condition and operations. 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.
COMPETITION - WE ARE SMALLER AND LESS EXPERIENCED THAN MOST OF OUR COMPETITORS IN THE GULF OF MEXICO.
Competition in the oil and gas industry is intense, particularly in the Gulf of Mexico. We compete with major and independent oil and gas companies for property acquisitions and for the equipment and labor required to operate and develop such properties. Most of Basin's competitors have financial and other resources substantially greater than ours. We commenced operations in the Gulf of Mexico area during 1996, where we had not previously been active. Competition from major and large independent oil and gas companies is significantly greater in this area than in the Rocky Mountain region, where Basin had conducted all of its previous operations.
PRINCIPAL STOCKHOLDER - HE 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 18% of Basin's outstanding shares. 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.
DEPENDENCE ON KEY PERSONNEL
Basin depends to a large extent on the services of its founder and CEO, Michael Smith, and certain other senior management personnel in Denver and Houston. The loss of the services of Mr. Smith or other key personnel could have a potential adverse effect on Basin's operations.
YEAR 2000 READINESS DISCLOSURE AND STATEMENT - BASIN OR ITS BUSINESS PARTNERS MAY NOT BE YEAR 2000 COMPLIANT, WHICH COULD RESULT IN DISRUPTION OF OUR OPERATIONS.
Basin expects to have completed its assessment, identification, remediation and testing of the Year 2000 readiness of its critical Information Technology ("IT") systems and its non-IT systems containing embedded microprocessors before January 1, 2000, and to have received satisfactory assurances by that date from its business partners that they will be Year 2000 compliant insofar as their goods or services are material to Basin's business. However, there is no assurance that Basin's Year 2000 readiness project will succeed in accurately and completely identifying all potential problems or all potentially affected systems or in remedying all problems in its systems. There is no assurance that Basin's business partners will likewise succeed in their respective efforts to remedy their Year 2000 problems or that this will be apparent in time for Basin to formulate a contingency plan.
Between now and 2000 there will be increased competition for people with technical and managerial skills necessary to deal with the Year 2000 problem, and Basin or its business partners could face shortages of skilled personnel or other resources, such as particular microprocessors or components containing Year 2000-ready microprocessors. These shortages might delay or otherwise impair Basin's ability to assure that its critical systems or its partners systems are Year 2000 compliant.
It is particularly difficult to find and remediate all embedded microprocessors in non-IT systems. Some of the embedded microprocessors that fail to operate or that produce anomalous results may create system disruptions or failures. Some of these disruptions or failures may spread from the systems in which they are located to other systems causing adverse effects upon Basin's ability to maintain production operations, conduct new drilling operations, execute financial transactions, manage its reporting or fulfill its legal obligations. The embedded microprocessor problem is widely recognized as one of the more difficult aspects of the Year 2000 problems across industries and throughout the world. The possible adverse impact of the embedded microprocessor problem is not, and will not be, unique to Basin. If there are Year 2000-related failures in critical systems of Basin or its business partners that create substantial disruptions to Basin's business, the adverse impact on Basin could be material. Additionally, Year 2000 costs are difficult to estimate accurately because of unanticipated vendor delays, technical difficulties, the impact of tests of third-party systems, and similar events. Moreover, despite Basin's belief that its costs in becoming Year 2000 compliant will not be material, its cost assessments do not take into account the costs, if any, that might be incurred as a result of Year 2000-related failures that occur despite its compliance efforts.
ANTI-TAKEOVER PROVISIONS - THESE PROVISIONS 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. Basin adopted a Stockholders' Rights Plan in 1996. Under this Plan, holders of Basin's Common Stock received rights exercisable if a person or group of affiliated persons acquires 15% of Basin's outstanding Common Stock or commences a tender or exchange offer which would result in ownership of 15% or more of Basin's outstanding Common Stock. In addition, Basin has entered into agreements with certain of its executive officers which would require additional payments by Basin 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, the Company's oil and gas properties were all located in the Rocky Mountain region, primarily in the D-J Basin, Powder River Basin, and Green River Basin. During 1996, the Company sold its D-J Basin assets and initiated operations in the Gulf of Mexico. As of December 31, 1998, the Company's estimated proved reserves totaled approximately 8.7 million barrels of oil and 127.5 Bcf of natural gas, or 179.5 Bcfe. The estimated pre-tax present value of future net revenues from these proved reserves, using December 31, 1998 product prices held constant and a discount rate of 10%, totaled approximately $164.5 million. Gulf of Mexico properties accounted for 75% of the Company's proved reserve quantities at December 31, 1998, and 92% of the related pre-tax present value of future net revenues estimated as of that date. Weighted average price used for purposes of estimating the Company's proved reserves at December 31, 1998 were $10.31 per barrel of oil and $1.99 per Mcf of natural gas.
In addition to its proved properties as of December 31, 1998, the Company owned mineral rights under 255,141 gross undeveloped acres, or 180,816 net undeveloped acres, of which more than half is located in the Gulf of Mexico. The Company had also licensed 3-D seismic data covering approximately 600 lease blocks, and 2-D data covering approximately 375,000 miles, in the Gulf of Mexico. The Company's undeveloped acreage in the Gulf of Mexico at the end of 1998 contained over 40 exploratory prospects identified by the Company's geoscientists, based upon their interpretations of 3-D seismic and other data.
The Company's Gulf of Mexico proved reserves as of December 31, 1998 were distributed among 18 fields. Production had been established from 14 of these fields at that date, and the other four fields were under development for first production. The Company's working interests in the 18 fields ranged from approximately 8% to 100%, with an average of 54%. Basin operates 11 of the 18 fields. These 11 properties account for approximately two-thirds of the Company's total proved reserves in the Gulf of Mexico. Six of the properties account for approximately 51% of the Company's proved reserve quantities and 67% of its related pre-tax present value of future net revenues from Gulf of Mexico assets as of December 31, 1998. These properties include Eugene Island Block 65, High Island Block A-568, West Cameron Block 45, West Cameron Block 56, West Delta Block 61 and West Delta Blocks 121/122. As is generally the case for Gulf of Mexico properties, the Company's properties in this area are generally expected to exhibit a high initial production rate followed by a steep decline in production after a relatively short period.
Most of the Company's proved reserves value related to onshore assets as of December 31, 1998 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 considerable number of undeveloped locations. Most of the Company's 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 the Company's 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 the Company's properties as of December 31, 1998, and to audit Basin's estimates of such data for the Company's remaining properties as of that date. The estimates prepared by Ryder Scott Company Petroleum Engineers covered properties that accounted for 53% of the Company's proved reserve quantities in the Gulf of Mexico as of December 31, 1998, and audits conducted by Ryder Scott Company covered the other properties. Estimates prepared by Ryder Scott Company or the Company's engineers were based upon a review of production histories and other geologic, economic, ownership, volumetric and engineering data. In determining the estimates of the reserve quantities that are economically recoverable, oil and gas prices and estimated development and production costs as of December 31, 1998 were utilized.
The following table sets forth estimates as of December 31, 1998 derived from Basin's reserve reports. The present values (discounted at 10 percent) of estimated future net revenues before income taxes shown in the table are not intended to represent the current market value of the estimated oil and gas reserves owned by Basin. For further information concerning the present value of future net revenue from these proved reserves, see Unaudited Supplemental Oil and Gas Reserve Information in the Consolidated Financial Statements.
The following table sets forth estimates of Basin's total proved reserves at December 31, 1998 by geographic area of operations:
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth herein represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment and the existence of development plans. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including geologic success, prices, future production levels and cost, that may not prove correct over time. Predictions about prices and future production levels are subject to great uncertainty, and the meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Oil and gas prices have fluctuated widely in recent years. There is no assurance that prices will not be materially higher or lower than the prices utilized in estimating Basin's reserves.
The weighted average sales prices utilized for purposes of estimating Basin's proved reserves and future net revenues therefrom as of December 31, 1998 were $10.31 per Bbl for oil and $1.99 per Mcf for gas. These prices are below the average prices prevailing during most of 1998, when the Company realized average oil and gas prices of $11.80 per Bbl and $2.07 per Mcf, respectively, before hedging effects.
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 are operated by it, 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 the Company as of December 31, 1998. Undeveloped acreage includes leasehold interests which may already have been classified as containing proved undeveloped reserves.
(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 may be considered undeveloped for certain formations, but have only been included as developed acreage in the presentation above.
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 306 gross (202 net) producing oil wells and 77 gross (49 net) producing gas wells as of December 31, 1998. A well is categorized under state reporting regulations as an oil well or a gas well based upon the ratio of gas to oil produced when it first commenced production, and such designation may not be indicative of current production.
DEVELOPMENT, EXPLORATION AND ACQUISITION EXPENDITURES
The following table sets forth certain information regarding the costs incurred by Basin in its development, exploration and acquisition activities during the periods indicated.
(1) Excludes $4,914,000, $1,113,000 and $150,000 of costs recouped through the resale of partial interests in prospects to industry partners in 1996, 1997 and 1998, respectively.
DRILLING ACTIVITY
The following table sets forth the wells drilled and completed by Basin during the periods indicated.
PRESENT ACTIVITIES
On March 17, 1999, the Company submitted apparent winning bids for five tracts at the Central Gulf of Mexico lease sale held by the MMS. Such tracts comprised 24,023 gross and net undeveloped acres offshore Louisiana. If all five tracts are awarded by the MMS, which can choose to reject all bids for a given lease, the Company's aggregate cost for the related leasehold bonuses will total approximately $3.0 million.
During 1999, through March 17, the Company's Gulf of Mexico activities have included completion of three (1.95 net) exploratory wells that were successfully drilled in 1998, drilling of two (0.80 net) exploratory wells, of which one (0.15 net) well was an apparent discovery, and the drilling of one successful development (0.65 net) well. The
Company also participated in one (0.60 net) exploratory well in Wyoming, which was abandoned in February 1999 due to an apparent underground blowout, but which is currently being re-drilled.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
The Company 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 security holders during the fourth quarter of 1998.
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, 1998 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 the Company's common stock as reported by the Nasdaq National Market for the last two calendar years.
The Company's policy is to retain earnings to support the growth of the Company's business. Accordingly, the Board of Directors of the Company has never declared a cash dividend on its Common Stock and has no present plan to do so. A credit agreement with the Company's bank group limits the Company's ability to pay dividends, re-acquire shares of its common stock or make certain other distributions.
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 in an understanding of the Company's results of operations for the three-year period ended December 31, 1998 and its present financial condition. The Company's consolidated financial statements and notes thereto, which are presented elsewhere herewith, contain additional detailed information that should be referred to in conjunction with a review of this material.
HISTORY AND OVERVIEW
Basin is a domestic independent oil and gas company that conducts exploration, acquisition, exploitation and production activities in the shallow waters of the Gulf of Mexico and selected areas onshore.
The Company commenced operations in 1981 and completed an initial public offering of its common stock in 1992. From its inception through 1991, Basin primarily acquired, developed and exploited properties in the Denver-Julesburg ("D-J") Basin in eastern Colorado. The Company subsequently expanded into other areas within the Rocky Mountain region and initiated exploration activities.
During 1995, the Company's capital expenditures on oil and gas properties declined to $16 million, from $67 million the year before, due primarily to fewer quality investment opportunities identified in the Company's core operating areas and limited unutilized borrowing capacity under the Company's revolving line of credit with its bank group (the "Credit Facility"). Each of these factors was exacerbated by depressed regional gas prices.
In response to these developments and management's assessment of alternative investment opportunities, the Company implemented a significant redirection of its business strategy and operations between late-1995 and mid-1996, which included: (i) the addition of new financial, technical and business development members to its senior management; (ii) the sale of its D-J Basin properties for $123.5 million (the "D-J Sales"); (iii) establishment of a Houston-based Gulf of Mexico exploration team through hiring geoscientists and petroleum engineers with substantial experience operating in the shallow waters of the Gulf of Mexico; and (iv) a substantial reduction in corporate general and administrative overhead.
The D-J Sales, which occurred in two transactions closed in March and June 1996, enabled the Company to eliminate its long-term debt and establish cash reserves, thus providing considerable liquidity for investments in new capital projects. However, the divestitures reduced the Company's estimated proved oil and gas reserves and production rates at the time by approximately 70%, resulting in a significant initial decline in revenue and cash flow.
The Company began Gulf of Mexico activities in 1996 with no initial property base in the region and early investments related primarily to acquisitions of three-dimensional seismic data and exploratory leasehold interests and overhead. The Company's first significant discovery in the Gulf of Mexico was the Eugene Island Block 65 #1 well, which was drilling at the end of 1996 and completed in 1997. The Company realized first production from Gulf of Mexico assets in August 1997 when it brought two wells drilled on Eugene Island Block 65 on-line, providing the first significant addition to the Company's producing property base following the D-J Sales. The Company added other proved properties in the Gulf of Mexico in 1997 and 1998 through both exploratory drilling and acquisitions and as of December 31, 1998 owned interests in 18 proved properties in the area, of which 14 were producing and four were under development for first production. Several of the properties producing at that date also had proved nonproducing reserves under development. Through December 31, 1998, the Company had drilled a total of 31 wells in the Gulf of Mexico, of which 20, or 65%, had been successful. The Company's estimated proved oil and gas reserves increased from 62.6 Bcfe as of December 31, 1995, pro forma the D-J Sales, to 179.5 Bcfe at the end of 1998. As described below, Basin's net production has increased significantly since mid-1997, as Gulf of Mexico properties have been brought on-line, and the Company expects further increases in 1999.
During 1998, the Company's capital expenditures totaled approximately $107 million. Approximately 96% of these investments related to operations in the Gulf of Mexico, including costs incurred for exploratory leaseholds, geological and geophysical data, exploratory drilling, and completion and development activities. Capital expenditures in 1998 were funded with a combination of cash flow, working capital, and borrowings under the Credit Facility.
The Company closed 1998 with a working capital deficit of approximately $13 million, long-term debt of $80 million, and stockholders' equity of $94 million. Stockholders' equity at the end of the period reflected the impact of a $38.5 million pre-tax non-cash impairment charge in the fourth quarter of 1998 to reduce the carrying value of the Company's oil and gas properties. This charge, which had no impact on the Company's cash flow or its borrowing capacity under the Credit Facility, was precipitated by low oil and gas prices in effect at year-end.
The Company's preliminary budget for 1999 provides for capital investments of approximately $65 million, subject to potential increase should proceeds be realized from asset sales. This budget provides for exploratory drilling activities comparable to the level of such activities in 1998, and for continued expeditious development of drilling successes. The 1999 budget provides for a smaller current year investment in prospect leaseholds than in 1998, and anticipates cost savings realizable from lower rates for drilling rigs and other oilfield goods and services than were
applicable during much of 1998. This budget may be revised up or down due to a number of factors, including future developments that impact availability of capital.
OPERATING ENVIRONMENT
Basin's results of operations are significantly impacted by oil and gas price levels, which are volatile and largely beyond the Company's control. Changes in oil and gas prices can also impact the amount and terms of external capital resources available to the Company.
Gas prices generally respond to North American supply and demand conditions, including the effects of weather, whereas 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 can significantly impact prices, however. During the past several months, the markets for both oil and gas have generally reflected ample supply and price weakness due to a number of factors, including a second consecutive unusually warm winter in North America. There are well-developed futures markets for oil and gas that provide indications of expected future prices for each product. These prices are frequently substantially different than current prices reflected on the spot market. Presently, these markets reflect expectations of a future recovery of oil and gas prices, particularly for gas, which accounted for 80% of the Company's total production in 1998. Expectations will change in response to future developments and higher future prices may not actually materialize.
Hedging transactions can be entered into based on prices reflected in commodity futures markets. The Company periodically enters into fixed price sales agreements or other hedging transactions to take advantage of prices that it believes to be attractive and to reduce volatility of net price realizations. The Company has executed various hedging transactions to mitigate its exposure to further commodity price weakness, as described herein under Liquidity and Capital Resources and in the Notes to Consolidated Financial Statements. However, since its hedges cover only a portion of its anticipated future production, the Company remains vulnerable to the potential effects of low prices.
The decline in oil and gas prices during the past year has negatively impacted access to capital resources for most energy companies, including Basin. Besides unfavorably affecting cash flow, this weakness in oil and gas prices has increased the cost of issuing long-term debt or equity securities and made the ability to issue such securities, at any price, less certain.
For oil and gas producers, these effects have been partially mitigated by improvements in the environment for acquisition of proved and unproved oil and gas properties, and costs of conducting exploration and development activities. In the opinion of management, diminished capital resources for energy companies, in the aggregate, has resulted in significant overall improvement of the quality and terms of investment opportunities that are currently available, compared to the period preceding the decline in oil and gas prices that occurred during the past year. In addition to an enhanced market for acquirors of exploratory prospects or producing properties, there have been substantial reductions in the costs of oilfield goods and services. At various times in the recent past, demand for oil and gas drilling rigs and other oilfield products and services has strained available capacity, leading to high cost levels, delays in obtaining materials and services, and instances of decreased quality of goods and services. Such conditions do not presently apply, and availability of and costs for such goods and services have improved markedly since mid-1998. As an example, the day rate for a typical shallow-water jack-up drilling rig used by the Company in the Gulf of Mexico has declined from approximately $40,000 to $15,000. Other costs have declined by smaller amounts, but still significantly. As noted, these conditions reflect reduced demand for such goods and services in an environment of relatively low oil and gas prices and, as such, some reversal would be expected if oil and gas prices strengthen.
The Company's Gulf of Mexico exploration activities are dependent on the Company's ability to continue to identify prospects and obtain interests in prospect leaseholds. The Company generally utilizes speculative three-dimensional seismic data as a tool in its prospect generation. This data is not proprietary and is available to competitors, which tends to increase the number of potential competitors for, and cost of, available prospects. During 1998, the Company was successful in expanding its inventory of potential exploratory drilling locations from approximately 30 to 40, while drilling 16 test wells. The Company also participated in submitting high bids for five leases with identified exploratory prospects at a Central Gulf of Mexico lease sale held in March 1999. This inventory of prospects, the majority of which are 100%-owned by the Company, represents more than a two-year set of drilling opportunities for Basin, based on both historical and anticipated drilling activity levels. However, the Company faces
competition for prospects from many better-capitalized oil and gas companies and there is no assurance that over the longer term, the Company will be able to continue to acquire interests in prospects at acceptable costs to replenish its inventory of prospects as these are drilled. The Company seeks to mitigate this risk by pursuing prospect ownership through a number of avenues, including lease sales, farm-ins, exchanges, and acquisitions. The Company also plans to selectively evaluate and pursue other investment opportunities, including onshore exploration and acquisitions of properties with proved oil and gas reserves, to complement its core exploration activities in the Gulf of Mexico.
RESULTS OF OPERATIONS
The following table sets forth certain operating information for the three years ended December 31, 1998. Because a substantial portion of the Company's operations was conducted in the D-J Basin through mid-1996 when the D-J Sales were consummated, and because the Company initiated Gulf of Mexico operations in 1996 and realized its first production from Gulf of Mexico properties in August 1997, period-to-period comparisons of results of operations may not be meaningful or indicative of future results.
1998 COMPARED TO 1997
As noted, the Company established its first production from Gulf of Mexico assets in the second half of 1997. This development, and production subsequently added from other Gulf of Mexico properties, significantly impacted the Company's results of operations. To assist in interpreting year-to-year comparisons, the following quarterly data is provided for the two-year period ended December 31, 1998.
REVENUE. Oil and gas sales for 1998 increased by $24.2 million, or 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, from $2.82 per Mcfe in 1997 to $2.21 per Mcfe in 1998. Hedging transactions had the effect of reducing oil and gas sales by $0.5 million, or $0.06 per Mcfe, in 1997 and increasing sales by $3.5 million, or $0.16 per Mcfe, in 1998.
The increase in production volumes from 8,653 MMcfe in 1997 to 21,966 MMcfe in 1998 was attributable to commencement of production at nine offshore properties at various times during 1998, and greater contributions from offshore properties acquired or brought on-line during the second half of 1997, partially offset by natural depletion. The decline in production between the third and fourth quarters of 1998 was largely due to the temporary loss of production from a major well, which was placed back on-line in the first quarter of 1999, after a re-completion operation.
LEASE OPERATING EXPENSES. Lease operating expenses ("LOE") increased in 1998 from the prior year by $3.7 million, or 80%, but LOE per Mcfe produced declined by 28% to $0.38, compared to $0.53 in 1997. As shown in the above table of quarterly data, the Company's LOE per Mcfe has generally improved as Gulf of Mexico production has increased, beginning with the third quarter of 1997. An offset to this pattern in the first half of 1998 primarily reflects costs related to the absorption of properties acquired in late-1997 from bankrupt Midcon Offshore, Inc. Typically, the Company's Gulf of Mexico properties have significantly lower unit operating costs than its Rocky Mountain assets. The relatively low per-unit operating cost of the Company's 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 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 price realizations on such production. Production from properties in federal waters offshore 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 $19.2 million, or 180%, in 1998 to $29.8 million. 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 the Company's historical average. The increased unit cost of additions in 1998 reflects the substantial portion of the Company's 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 the Company's 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 $0.7 million, or 19%, from 1997 levels, to $4.4 million. The increase in 1998 resulted primarily from incremental costs incurred to manage expanded operations in the Gulf of Mexico. On a per Mcfe basis, general and administrative expenses during the two-year period generally declined as production volumes increased, as reflected in the table above.
INTEREST AND OTHER EXPENSE. Interest and other expense for 1998 was $2.0 million, representing an increase of $1.3 million, or 166%, compared to 1997. The variance was attributable to an increase in average borrowings offset by a slight reduction in the Company's average effective interest rate. 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. During 1998, the Company 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 interest rate of 6.7% in 1997. Substantially all of the borrowings in both years were under the Credit Facility.
PROPERTY IMPAIRMENT. During 1998, the Company recognized a property impairment charge of $38.5 million, as the result of the capitalized costs of its oil and gas properties exceeding a "ceiling" on such costs computed in accordance with prescribed guidelines for companies utilizing the full cost accounting method. The charge, which had no impact on the Company's cash flows or its bank 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 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.
1997 COMPARED TO 1996
The sale of the Company's D-J Basin assets in the first half of 1996 and realization of first production from Gulf of Mexico assets in the second half of 1997 result in year-to-year comparisons that obscure important underlying trends. To assist in understanding such trends, the following quarterly data is provided for the two-year period ended December 31, 1997.
REVENUE. Oil and gas sales for 1997 increased by $6.2 million, or 34%, to $24.4 million, due largely to improved average price realizations. An 83% increase in gas prices, offset by a 6% decrease in oil prices, yielded a 26% increase in revenue per net equivalent unit produced, from $2.23 per Mcfe in 1996 to $2.82 per Mcfe in 1997. Hedging transactions had the effect of reducing oil and gas sales by $0.5 million in both years.
Production increased by 6% in net equivalent units, from 8,160 MMcfe in 1996 to 8,653 MMcfe in 1997. The relatively small change in production volumes from year-to-year masks significant changes during each year due to the D-J Sales in March and June 1996 and the commencement of Gulf of Mexico production in August 1997.
In conjunction with the second D-J Sale transaction, which closed in June 1996, the Company recognized a non-recurring $22.5 million gain. Other revenue reported in both 1996 and 1997 primarily represented interest income on cash equivalents held after the second D-J Sale transaction prior to redeploying those proceeds into investments in oil and gas properties.
LEASE OPERATING EXPENSES. LOE declined in 1997 from the prior year by $0.2 million, or 4%, and LOE per Mcfe produced declined by 10%, to $0.53 in 1997, compared to $0.59 in 1996. Again, the relatively small changes from year-to-year do not reflect significant variances within each year. Average LOE per Mcfe by quarter reflects that both the properties included in the D-J Sales and the Gulf of Mexico properties that began contributing in the second half of 1997 have significantly lower unit operating costs than the Company's retained Rocky Mountain assets, which have high unit operating costs due to relatively low average production rates per well and a high proportion of oil production, which is generally more costly to produce than gas.
PRODUCTION TAXES. Production taxes for 1997 decreased by $0.6 million, or 31%, as the result of reduced sales from onshore properties in 1997, due to inclusion in 1996 of production from D-J Basin properties prior to the D-J Sales. Production from properties in federal waters offshore is generally not subject to production taxes and such taxes did not increase in the second half of 1997 as the Company added Gulf of Mexico production. Production taxes therefore declined as a percentage of oil and gas sales, averaging 5.2% for all of 1997 and 3.3% in the second half of the year, compared to 10.1% in 1996.
DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and amortization expense increased by $3.0 million, or 40%, in 1997 to $10.6 million. The average depletion rate of $1.12 per Mcfe of production in 1997 represents a 37% increase from the $0.82 per Mcfe recorded in 1996. The higher rate is due to the addition of proved reserves in 1997 at a higher average unit cost than the Company's historical average and to the unfavorable impact on estimated proved reserve quantities of using lower assumed future oil and gas prices at the end of 1997 than at the end of 1996. The increased unit cost of additions in 1997 reflects the substantial portion of the Company's capital expenditures in 1997 related to the Gulf of Mexico, where higher unit costs are generally associated with reserves having a higher value per unit than the Company's onshore properties, due to typically faster recoveries of reserves, lower production costs, and higher average realizable gas prices.
GENERAL AND ADMINISTRATIVE EXPENSES, NET. General and administrative expenses in 1997 decreased by $0.2 million, or 4%, from 1996 levels, to $3.7 million. The decrease in 1997 resulted primarily from staff reductions made in mid-1996 in conjunction with the D-J Sales and related reductions in office rent expense attributable to the Company's relocation to smaller space. These savings, which benefitted all of 1997 but only a portion of 1996, were partially offset by higher bonus awards and stock-based incentive compensation costs recorded in 1997. On a per Mcfe basis, general and administrative expenses during the two-year period generally varied inversely with production volumes.
INTEREST AND OTHER EXPENSE. Interest and other expense for 1997 was $0.8 million, representing a decrease of $1.5 million, or 66%, compared to 1996. The variance was attributable to a decrease in average borrowings after the D-J Sales and a reduction in the Company's average effective interest rate, reflecting lower prevailing market interest rates and more favorable borrowing terms obtained after the D-J Sales. During 1997, the Company had average outstanding debt of $10.2 million with an average effective interest rate of 6.7%, compared to average borrowings of $28.2 million and an average interest rate of 8.0% in 1996. Substantially all of the borrowings in both years were under the Credit Facility.
INCOME TAX PROVISION. The income tax provision for 1997 approximates the amount that would be calculated by applying statutory income tax rates to income before income taxes. The 1997 current provision for income taxes was decreased, and the deferred provision was increased, by approximately $0.5 million due to a change in estimate of current taxes payable for fiscal 1996. The difference between the income tax provision recorded for 1996 and the amount that would be calculated by applying statutory income tax rates to income before income taxes is due primarily to reversal of a previously established $2.2 million deferred tax asset valuation allowance.
LIQUIDITY AND CAPITAL RESOURCES
Historically, the Company's principal sources of capital have been cash flow from operations, the Credit Facility, proceeds from asset sales, and proceeds from sales of common stock. The Company's principal uses of capital have been for the exploration, acquisition, development and exploitation of oil and gas properties.
The Company's oil and gas capital expenditures during 1998 totaled approximately $106.7 million. Net cash provided by operations before changes in working capital totaled $33.7 million. The remainder of 1998 capital expenditures was funded primarily through a $69.0 million increase in borrowings under the Credit Facility and a $3.2 million reduction in net working capital. The Company closed 1998 with a working capital deficit of approximately $13.2 million and long-term debt of $80.0 million, all of which was outstanding under the Credit Facility. The borrowing base established under the Credit Facility as of January 1, 1999 was $110 million.
For 1999, the Company has established an initial budget for exploration and development activities of approximately $65 million, subject to potential increase for proceeds from asset sales, if any. The Company plans to fund such investments with cash flow from operations, which is expected to increase from 1998 levels because of projected production increases, and additional borrowings under the Credit Facility. This budget is subject to revision to reflect future developments. It may be impacted by oil and gas price levels, future re-determinations of the borrowing base under the Credit Facility, and other factors. Although this budget is not predicated on a future sale of securities, the Company may choose to issue securities in certain circumstances, in which case the level of the Company's capital expenditures in 1999 would likely increase. Compared to actual capital expenditures in 1998, the lower budget presently established for 1999 reflects a number of considerations including, but not limited to, lower assumed oil and gas prices and higher initial debt levels. The impact on drilling activity in the current year, compared to 1998, is expected to be modest, as most of the decline in expenditures is expected to be offset by lower service sector costs or reflected in reduced investments for acquisitions of prospect leaseholds. The Company's investments in leaseholds in 1998 significantly increased its inventory of exploratory prospects in the Gulf of Mexico, to a level representing a multi-year set of drilling opportunities. The Company's initial budget for 1999 anticipates investments at a level to approximately maintain, rather than significantly expand, its inventory of Gulf of Mexico prospects.
PRODUCTION AND CASH FLOW. The Company's cash flow from operations is generally determined largely by its production level and oil and gas prices. Since 1996, the Company has made significant investments to initiate and then expand its operations in the Gulf of Mexico. These investments have resulted in a production ramp-up that increased the Company's 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 68.8 MMcfe per day in the third quarter of 1998, before a decline to 65.9 MMcfe per day in the fourth quarter of 1998 when a significant well was taken off-line for re-completion operations. Based primarily on estimates reflected in the Company's year-end 1998 reserve reports, the Company anticipates that its net production in 1999 will be at least 50% greater than during 1998, when production totaled 21,966 MMcfe. The expected increase is attributable to projected production from Gulf of Mexico properties with proved reserves at the end of 1998 that were either on-line for only a portion of 1998 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 1999 will be dependent upon meeting scheduled dates for commencement of production from wells not yet on-line at the end of 1998, and upon achieving projected performance from major wells, including certain wells with little or no production history to-date. Although management and the Company's independent engineering consultants believe the projections are reasonable, there is no assurance that they will be met.
MARKETING AND HEDGING TRANSACTIONS. The Company's production is generally sold under month-to-month contracts at prevailing prices. From time-to-time, however, as conditions are deemed to warrant, Basin has entered into
hedging transactions or fixed price sales contracts for a portion of its oil and gas production. The purposes of these transactions are to limit the Company's exposure to future oil and gas price declines and achieve a more predictable cash flow. However, such contracts also limit the benefits the Company would realize if prices increase. Hedging contracts reduced the Company's total revenue by $0.5 million in each of 1996 and 1997, and increased revenue by $3.5 million in 1998.
As of February 24, 1999, the Company was a party to the following fixed price swap arrangements (one MMBtu approximates one Mcf of natural gas):
In addition, the Company periodically enters into spread trades or options transactions related to oil or natural gas futures markets. Under a spread trade, fixed prices under a hedging contract are determined in the future by reference to the price of an underlying contract. Such positions may enable the Company to lock in favorable fixed prices for future hedging positions, but can also result in unfavorable fixed price contracts if the reference price represented by the underlying contract declines. As of February 24, 1999, the Company had entered into spread trades for natural gas providing for a fixed price for 20,000 MMBtu per day for the period of March 2000 through September 2000 to be established in the future upon an election by the Company by reference to the underlying NYMEX October 1999 contract price less $0.28. The Company also had sold call options for 10,000 MMBtu of natural gas per day for the period from March 1999 through April 1999 with a strike price of $1.93 per MMBtu, and from January 1999 through December 2001 with an average strike price of $2.50 per MMBtu. Call options had also been sold covering a quantity of 1,000 barrels of oil per day for the period from July 1999 through December 1999, at a strike price of $16.75 per barrel. At December 31, 1998, the estimated fair value of the open oil and gas price hedging contracts was an unrealized gain of approximately $1,170,000.
CREDIT FACILITY. Effective January 1, 1999, the Company entered into an Amended and Restated Credit Agreement (the "Credit Agreement") with its existing bank group. The Credit Agreement provides for borrowings of up to $110 million under two combined facilities. Facility A was initially established at $90 million and represents the borrowing base that is considered to be "conforming" based upon the bank's customary practices and standards in making conventional borrowing base determinations for oil and gas producers. Facility B, initially established at $20 million, is a shorter-term supplemental line of credit. The Credit Agreement provides for the interest rate on borrowings to be determined by reference to the prime rate or LIBOR, at the Company's election. Facility A provides for a varying spread of 0% to 0.25% to be added to the prime rate, or 0.75% to 1.5% to be applied to LIBOR, based upon the Company's facility usage ratio. Facility B provides for a spread of 3.5% to be added to the prime rate, or 4.75% to be applied to LIBOR subject to a 0.25% increase in such spreads, effective June 1, 1999. The Credit Agreement provides for borrowings to be revolving loans until November 30, 2001, at which time the outstanding balance will be converted into a four-year amortizing term loan unless the Credit Agreement is amended, and subject to the scheduled termination of Facility B effective May 31, 2000. The borrowing base under the Credit Agreement is scheduled to be re-determined at three-month intervals until Facility B is retired, and then at six-month intervals 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 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, 1998 was 6.2%. The Company's annual interest costs will fluctuate based upon fluctuations in short-term interest rates. Assuming debt outstanding during 1999 remained unchanged from the amount outstanding at the end of 1998, the impact on interest expense, before amounts capitalized, of a ten percent change in the average interest rate would be
approximately $500,000. As the interest rate is variable and is reflective of current market conditions, the carrying value of the Company's debt approximates its fair value.
Borrowing base re-determinations conducted by the bank group reflect a number of estimates and assumptions including, but not limited to, future production from the Company's proved properties, risk factors for proved reserves, projected oil and gas prices, future operating and development costs, and 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, the Company cannot predict what level of borrowing base will be established at any future determination date. The provision for Facility B was intended, in part, to provide short-term funds to develop the Company's proved undeveloped and proved developed nonproducing reserves in the Gulf of Mexico. It is anticipated that funds drawn under Facility B will be retired through expansion of Facility A, if the Company's reserve values are sufficiently increased, or that Facility B will be repaid from cash flows or proceeds from asset or security sales. At March 19, 1999, $90 million was outstanding under Facility A and $2.5 million was outstanding under Facility B.
Positive or negative changes in the borrowing base during 1999 would be likely to affect the Company's capital expenditures during the year. Increases, supported by performance of the Company's properties, drilling results, and/or higher oil and gas prices, could improve the Company's ability to grow. Decreases would adversely affect the Company's liquidity and capital resources, potentially resulting in a reduction of planned capital expenditures or the sale of assets or securities.
CAPITAL EXPENDITURES. Since the beginning of 1996, Basin has focused its exploration activities in the shallow waters of the Gulf of Mexico, primarily off the coast of Louisiana. Recently, the Company began to direct a small portion of its exploration budget toward onshore opportunities, and it pursues acquisition, development, and exploitation opportunities in the vicinity of the Company's Gulf of Mexico exploration operations, in the Rocky Mountain region where Basin has an existing base of proved reserves and producing wells, and in certain other major domestic producing basins where the Company believes significant upside potential exists. The Company's 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.
The Company's capital expenditures in 1998 totaled approximately $107 million, of which 96% related to operations in the Gulf of Mexico. Approximately $28 million was invested in acquisitions of exploratory leaseholds and geological and geophysical data in the Gulf of Mexico. Approximately $68 million related to Gulf of Mexico drilling, completion, and related development costs. The remainder related to small proved property acquisitions and activities onshore. Gulf of Mexico operations in 1998 included ongoing development of nine productive wells drilled or acquired in 1997, participation in the drilling of 17 wells, of which 11 were successful, and development costs related to the successful wells drilled during the year.
The Company currently estimates that its capital expenditures for exploration and development in 1999 will be approximately $65 million, subject to potential increase if proceeds are realized from asset sales. This budget primarily provides for: development of seven properties with one or more successful wells yet to commence sustained production as of the end of 1998; investments in seismic data and prospect leaseholds; participation in approximately six net (13 to 15 gross) exploratory wells in the Gulf of Mexico; participation in a small number of onshore exploration opportunities; development of assumed 1999 prospect discoveries; and continued exploitation of the Company's other offshore and onshore properties. Although several locations for planned 1999 exploratory drilling have been identified, a significant portion of the 1999 exploration budget is currently unallocated, pending acquisition of drilling partners and formation of joint ventures to conduct exploratory operations. The smaller budget in 1999, compared to actual expenditures in 1998, is not expected to require a significant reduction in drilling activity because of a planned substantial reduction in acquisitions of exploratory leaseholds in 1999 and benefits expected to be realized from the substantial decline in service sector costs during the past year. The reduced budget for exploratory leaseholds reflects the unusually large investment made by the Company in 1998 to initially establish a multi-year inventory of drilling prospects. New investments planned for 1999 will seek to approximately maintain this inventory level rather than significantly expand it.
The Company also intends to pursue acquisitions of properties with proved and probable reserves as an integral part of its overall business strategy, with the expectation that these efforts will result in significant investment activity over time. At this time, no portion of the Company's 1999 budget has been specifically allocated for acquisitions of proved
properties. If such a transaction is executed, it will likely require a re-allocation of budget from other planned activities and/or external financing.
The amount and allocation of future capital expenditures will depend on a number of factors that are not entirely within the Company'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. The Company's planned capital expenditures are also based on estimates regarding availability of capital that depend on assumptions and estimates regarding production, oil and gas prices, and borrowing base re-determinations under the Company's Credit Agreement. Due to these uncertainties, actual capital expenditures may vary significantly from current expectations.
Should the Company seek to increase its capital expenditure budget for 1999 to respond to drilling opportunities that it deems exceptional, to fund development of a greater number or larger-sized exploratory successes than assumed, or for acquisitions of proved and probable reserves or prospect leaseholds, the Company may consider raising additional capital through issuance of debt and/or equity securities. The Company may also seek additional debt or equity financing in the absence of a specific planned increase in capital expenditures, in order to increase financial flexibility to capitalize on future opportunities.
YEAR 2000 READINESS DISCLOSURE AND STATEMENT
Readers are cautioned that the forward-looking statements contained in the following Year 2000 discussion should be read in conjunction with the Company's 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 the Company and the parties with whom it does business.
STATE OF READINESS. The Company has created an internal committee to assess the Company's Year 2000 readiness and to lead its remediation efforts. The committee is composed of the general counsel, chief financial officer, controller, and manager of information systems. The committee's objective is to prevent loss or impairment of those functions material to the Company's operations and business continuity or to avoid potential liability to third parties. At the direction of the committee, department heads and managers have assessed and remediated the Company's IT and non-IT systems, and have communicated with the Company's business partners regarding the status of their assessment and remediation efforts, with the results summarized below.
The Company has completed an assessment of its IT systems to determine whether they are Year 2000 compliant. The licensors of both the Company's core financial, land and operations software system and its underlying operating system have certified that such software is Year 2000 compliant. The Company's Gulf of Mexico seismic data interpretation software system is not currently Year 2000 compliant, but the Company has begun an upgrade of that system with software which the licensor has represented will be compliant. The Company is also upgrading its reservoir economics software to make it Year 2000 compliant. The Company expects the upgrade and testing of these software systems to be completed by July 1999. Additionally, the Company has assessed other less critical IT systems and believes them to be compliant.
The Company also relies on non-IT systems, such as office telephones, facsimile machines, HVAC systems and elevators in its leased offices, security systems, and automated measuring equipment on platforms and other production facilities, which may have embedded technology such as micro-controllers. Department heads and managers have identified those non-IT systems which may be susceptible to failure or impairment by reason of Year 2000 problems and which are potentially critical to the Company's operations and business continuity. Based on that review, the Company
has sent written inquiries to the suppliers of those systems to determine their Year 2000 compliance. The vendors of the Company's communications systems and the property managers of the buildings in which the Company's Houston and Denver offices are situated have certified their systems to be Year 2000 compliant. The Company is still receiving and analyzing responses from vendors of those non-IT systems that may affect the Company's production operations. The operations department will follow up those inquiries with telephone interviews to assess the status of such systems. Assessment and remediation of non-IT systems should be completed by September 1999.
The Company has sent written inquiries to its significant suppliers, customers, banks, government agencies, benefit plan providers, and others with whom the Company has significant business relationships to determine the extent to which the Company is vulnerable to those third parties' failure to correct their own Year 2000 issues. To date, the Company has not received definitive responses from many of these entities and therefore cannot assess whether they are Year 2000 compliant or how their failure to be compliant would affect the Company. Those third parties who have responded have generally indicated that they are either Year 2000 compliant or expect to be compliant. Department heads and managers have compiled a list of critical third parties to whom telephone follow-up will be made. For Gulf of Mexico operations, these include representative vendors and suppliers who could supply necessary goods and services to maintain the Company's production operations and continue any ongoing or planned drilling activities. The Company expects to have this follow-up inquiry completed by July 1999 and will utilize those vendors and suppliers providing adequate assurances regarding their compliance.
ESTIMATED COMPLIANCE COSTS. The Company has relied primarily on its internal staff to assess its current Year 2000 readiness and does not anticipate extensive use of external resources to complete its assessment or remediation. The Company has not separately quantified its costs of internal resources on this project but does not expect that it will incur material costs in remediating its IT systems to be Year 2000 compliant. Costs incurred for the purchase of new software and hardware are capitalized and all other costs are expensed as incurred. The Company has not incurred, and does not anticipate that it will incur, costs for external resources in excess of $100,000 relating to the assessment and remediation of Year 2000 issues. That estimate does not include the cost of remediating problems caused by third-party vendors, customers, or other business partners, which the Company will not be able to estimate until the extent, if any, of their Year 2000 non-compliance is known.
RISKS OF NON-COMPLIANCE AND CONTINGENCY PLANS. As indicated above, the only critical IT systems which the Company believes are not yet Year 2000 compliant are its seismic data interpretation and reservoir economics systems, which should be compliant by July 1999. Accordingly, the Company does not expect Year 2000 issues to cause its IT systems to have any material adverse impact on its business, operations or financial condition. The Company believes that the potential impact, if any, of its non-critical IT systems not being Year 2000 compliant will at most require employees to manually complete otherwise automated tasks or calculations and should not impact the Company's ability to continue exploration, drilling, production or sales activities. The Company is not able to predict at this time what the impact could be of non-IT system failures but does not believe that there will be a material disruption of the Company's operations.
Until the Company has completed its inquiries to third parties, it will not be able to assess the potential impact of their failure to be Year 2000 compliant on the Company's operations, business, or financial condition. The most reasonably likely "worst case" impacts could be impairment of the Company's ability to deliver its production to, or receive payment from, third parties gathering and/or purchasing the Company's production from affected facilities, impairment of the ability of third-party suppliers or service companies to provide needed materials or services to the Company's planned or ongoing operations, thereby necessitating deferral or shut-in of exploration, development or production operations, and the inability of the Company to execute financial transactions with its banks or other third parties whose systems fail or misfunction. The Company currently has no reason to believe that any of these contingencies will occur or that its principal vendors, customers, and business partners will not be Year 2000 compliant.
The Company does not currently have a contingency plan under development or in place to address these potential problems. The Company does intend to develop contingency plans in response to testing its IT and non-IT systems and in response to the results of its third-party inquiries. These contingency plans may include installing back-up computer systems or equipment, temporarily replacing systems or equipment with manual processes, and identifying alternate suppliers, service companies and purchasers. The Company expects these plans to be complete by October 1999.
Basin's Year 2000 program is a continuing process that may result in changes to cost estimates and schedules as testing and business partner assessment progresses. Unexpected Year 2000 compliance problems of either the Company
or its vendors, customers, service providers, or other entities with whom it does business could have a material adverse impact on the Company's business, financial condition or operating results.
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 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 1999 Annual Meeting of Stockholders (the "Proxy Statement") to be filed with the Securities and Exchange Commission no later than April 30, 1999.
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, 1998 and 1997, 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, 1998. 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 generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Basin Exploration, Inc. and subsidiaries as of December 31, 1998 and 1997, and the results of their operations and their cash flow for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Denver, Colorado, February 24, 1999.
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, 1996, 1997 and 1998 (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. 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) 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 a reduction in oil revenue of $480,000 and $144,000 under hedging agreements in 1996 and 1997, respectively. The Company recognized a reduction in gas revenue of $383,000 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.
As of February 24, 1999, the Company was a party to the following fixed price swap arrangements (one MMBtu approximates one Mcf of natural gas):
In addition, the Company periodically enters into spread trades or options transactions related to oil or natural gas futures markets. Under a spread trade, fixed prices under a hedging contract are determined in the future by reference to the price of an underlying contract. Such positions may enable the Company to lock in favorable fixed prices for future hedging positions, but can also result in unfavorable fixed price contracts if the reference price represented by the underlying contract declines. As of February 24, 1999, the Company had entered into spread trades for natural gas providing for a fixed price for 20,000 MMBtu per day for the period of March 2000 through September 2000 to be established in the future upon an election by the Company by reference to the underlying NYMEX October 1999 contract price less $0.28. The Company also had sold call options for 10,000 MMBtu of natural gas per day for the period from March 1999 through April 1999 with a strike price of $1.93 per MMBtu, and from January 1999 through December 2001 with an average strike price of $2.50 per MMBtu. Call options had also been sold covering a quantity of 1,000 barrels of oil per day for the period from July 1999 through December 1999, at a strike price of $16.75 per barrel.
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, 1998, utilizing the then-applicable crude oil and natural gas strips. While it is not the Company's intention to terminate any of the arrangements, it is estimated that the Company would have
received approximately $1,170,000 to terminate the then-existing arrangements on December 31, 1998. 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 Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in 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 unless specific hedge accounting criteria are met. SFAS 133 is effective for the Company in 2000, 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 171,500 and 30,000 shares in 1996 and 1997, respectively, 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, the Company issued warrants to purchase 300,000 shares of the Company's common stock at an exercise price of $14.00 per share. Such warrants became exercisable on October 13, 1994 and have an expiration date of December 31, 1999. During 1997 and 1998, 48,523 and 79,145 warrants were exercised, respectively. The remaining 172,332 warrants were outstanding at December 31, 1998.
COMPREHENSIVE INCOME - The Company adopted SFAS 130, "Comprehensive Income," beginning with the fourth quarter of 1997. 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 AND DIVESTITURES OF OIL AND GAS PROPERTIES
In February 1996, the Company entered into agreements pursuant to which it sold all of its assets in the D-J Basin in two transactions closed in March and June 1996, respectively, for an aggregate sales price of $123,500,000, effective January 1, 1996. Combined, these transactions resulted in Basin selling its interests in approximately two-thirds of its producing wells and 70% of its proved oil and gas reserves at December 31, 1995. The Company recognized a gain of $22,472,000 in conjunction with the second transaction. Revenue and expenses associated with the sold properties were included in the Company's results of operations through the respective closing dates.
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, the Company entered into an Amended and Restated Credit Agreement (the "Credit Agreement") with its existing bank group. The Credit Agreement provides for borrowings of up to $110,000,000 under two combined facilities. Facility A, initially established at $90,000,000, represents the borrowing base that is considered to be "conforming" , based upon the bank's then-current customary practices and standards in making conventional borrowing base determinations for oil and gas producers. Such practices and standards are intended to be substantially similar to the bank group's present practices, except for market-induced changes relating to pricing, costs and risk factors related to oil and gas reserves. Facility B, initially established at $20,000,000, is a shorter-term supplemental line of credit. The Credit Agreement provides for the interest rate on borrowings to be determined by reference to the prime rate or LIBOR, at the Company's election. Facility A provides for a varying spread of 0% to 0.25% to be added to the prime rate, or 0.75% to 1.5% to be applied to LIBOR, based upon the Company's facility usage ratio at the time. Facility B provides for a spread of 3.5% to be added to the prime rate or 4.75% to be applied to LIBOR, subject to a 0.25% increase in such spreads effective June 1, 1999. The Credit Agreement provides for borrowings to be revolving loans until November 30, 2001, 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, and subject to the scheduled termination of Facility B effective May 31, 2000. The borrowing base under the Credit Agreement is scheduled to be re-determined as of March l, 1999 and generally at three-month intervals thereafter until Facility B is retired, and then at six-month intervals 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, 1998 was 6.2%.
Outstanding debt at December 31, 1998 is payable as follows (in thousands):
(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 $96,000, $183,000 and $208,000, with respect to the Plan for the years ended December 31, 1996, 1997 and 1998, 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.
At December 31, 1998, a total of approximately 1,758,000 shares were available for grant under the plans. Options granted generally vest over three to four years, and expire after ten years. A total of 1,175,000 shares of the Company's common stock are subject to such plans as of December 31, 1998, including 186,000 non-vested shares of restricted stock and performance shares and 989,000 outstanding stock options.
The following table summarizes stock options activity for the years presented:
Additional information regarding outstanding options at December 31, 1998 is as follows:
The Company granted 25,000, 23,000 and 59,000 shares of restricted stock during 1996, 1997 and 1998, respectively. Related compensation expense was recognized in the amounts of approximately $98,000, $120,000 and $409,000 for the years ended December 31, 1996, 1997, and 1998, respectively. Cumulatively through December 31, 1998, 73,000 shares of restricted stock had been forfeited, 53,000 shares were no longer subject to restriction, and 81,000 shares of restricted stock remained subject to forfeiture.
The Company granted 55,000 and 50,000 performance shares during 1997 and 1998, 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. Related compensation expense was recognized in the amount of $447,000 and $367,000 for the years ended December 31, 1997 and 1998, respectively.
In October 1995, the Financial Accounting Standards Board issued SFAS 123, "Accounting for Stock-Based Compensation." SFAS 123 is effective for 1996 and after and recommends a fair value based method of accounting for employee stock compensation, including stock options. However, companies may choose to account for stock compensation using the intrinsic value based method as prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and provide pro forma disclosures of net income and earnings per share as if the fair value based method had been applied. The Company has elected to continue to account for stock compensation using the intrinsic value based method.
Had the Company elected to follow SFAS 123, the fair value of each option grant would have been estimated on the date of grant using the Black-Sholes option-pricing model with the following weighted-average assumptions 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 to and from third parties under various noncancelable lease arrangements. The following is a schedule of future minimum lease payments under these leases at December 31, 1998:
Payments related to these lease obligations were approximately $707,000, $990,000 and $1,096,000 for the years ended December 31, 1996, 1997 and 1998, respectively. Related receipts were $89,000, $502,000 and $506,000 in the years ended December 31, 1996, 1997 and 1998.
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 (benefit) computed at the federal statutory rate with income tax provisions recorded by the Company for each of the past three years are as follows:
The tax effects of significant temporary differences representing deferred tax assets and liabilities are as follows:
(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 $4,914,000, $1,113,000 and $150,000 of costs recouped through the resale of partial interests in prospects to industry partners in 1996, 1997 and 1998, respectively.
COSTS NOT BEING AMORTIZED - Oil and gas property costs not being amortized at December 31, 1998, consisted of $34,039,000 of leasehold and seismic costs, of which $2,669,000, $3,312,000 and $28,058,000 were incurred in 1996, 1997 and 1998, 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: $25.35 per barrel of oil and $3.02 per Mcf of gas at December 31, 1996; $16.34 per barrel of oil and $2.32 per Mcf of gas at December 31, 1997 and $10.31 per barrel of oil and $1.99 per Mcf of gas at December 31, 1998. 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, 1995, 1996 and 1997 and by Ryder Scott Company Petroleum Engineers at December 31, 1998. 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 $83,656,000, $160,230,000 and $164,485,000 as of December 31, 1996, 1997 and 1998, 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
- ------------------- (1) Filed herewith.
(2) Filed as an Exhibit to Basin's Registration Statement on Form S-1 as filed on March 17, 1992, Registration No. 33-46486, and incorporated herein by reference.
(3) Filed as an Exhibit to Amendment No. 1 to Basin's Registration Statement on Form S-1 as filed on April 21, 1992, Registration No. 33-46486, and incorporated herein by reference.
(4) Filed as an Exhibit to Basin's Registration Statement on Form S-1 as filed on October 25, 1993, Registration No. 33-70802, and incorporated herein by reference.
(5) Filed as an Exhibit to Form 8-K filed on December 10, 1994, and incorporated herein by reference.
(6) Filed as an Exhibit to Form 10-K/A-1 filed on June 26, 1995 and incorporated herein by reference.
(7) Filed as an Exhibit to Form 10-K filed on March 28, 1995, and incorporated herein by reference.
(8) Filed as an Exhibit to Form 8-K filed on February 26, 1996, and incorporated herein by reference.
(9) Filed as an Exhibit to Form 10-K filed on March 28, 1996, and incorporated herein by reference.
(10) Filed as an Exhibit to Form 10-K filed on March 31, 1997, and incorporated herein by reference.
(11) Filed as an Exhibit to Form 10-Q filed on August 12, 1997, and incorporated herein by reference.
(12) Filed as an Exhibit to Form 8-K filed on December 11, 1997, and incorporated herein by reference.
(13) Filed as an Exhibit to Form 10-K filed on March 31, 1998, and incorporated herein by reference.
(14) Filed as an Exhibit to Form 10-Q filed on May 14, 1998, and incorporated herein by reference.
(15) Filed as an Exhibit to Form 10-Q filed on November 13, 1998, 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 29, 1999 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.
Signature Title Date --------- ----- ----
/s/ MICHAEL S. SMITH President, Chief Executive March 29, 1999 - ------------------------ Officer and Chairman of the Michael S. Smith Board (Principal Executive Officer)
/s/ HOWARD L. BOIGON Vice President - General Counsel, March 29, 1999 - ------------------------ Secretary and Director Howard L. Boigon
/s/ NEIL L. STENBUCK Vice President, Chief Financial March 29, 1999 - ------------------------ Officer and Director Neil L. Stenbuck
/s/ JAMES A. TUELL Controller, Principal Accounting March 29, 1999 - ------------------------ Officer James A. Tuell
/s/ DONALD H. ANDERSON Director March 29, 1999 - ------------------------ Donald H. Anderson
/s/ JOHN F. GREENE Director March 29, 1999 - ------------------------ John F. Greene
/s/ J. PAUL HELLSTROM Director March 29, 1999 - ------------------------ J. Paul Hellstrom
/s/ MICHAEL A. NICOLAIS Director March 29, 1999 - ------------------------ Michael A. Nicolais
/s/ LARRY D. UNRUH Director March 29, 1999 - ------------------------ Larry D. Unruh