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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934 for the fiscal year ended December 31, 1997.
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
Commission File Number 0-20125
BASIN EXPLORATION, INC.
(Exact name of registrant as specified in its charter)
Delaware 84-1143307
(State or other jurisdiction (IRS Employer
of incorporation or organization) Identification No.)
370 Seventeenth Street, Suite 3400, Denver, Colorado 80202
(Address of principal executive offices) (Zip Code)
(303) 685-8000
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $.01 par value
(Title of Class)
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
[X] Yes [ ] No
As of March 26, 1998, the aggregate market value of the approximate
10,467,300 shares of voting stock held by non-affiliates of the registrant was
approximately $210,654,000 based upon the closing sale price of the Common Stock
on the Nasdaq Stock Market on March 26, 1998 of $20.13 per share.
As of March 26 1998, the registrant had 13,819,000 shares of Common Stock
outstanding.
DOCUMENT INCORPORATED BY REFERENCE
Parts of the following document are incorporated by reference to Part III of
this Form 10-K Report: Proxy Statement for the registrant's 1998 Annual Meeting
of Shareholders.
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CROSS-REFERENCE SHEET
PART I INTERNAL PAGE
Item 1. Business 1
Item 2. Properties 8
Item 3. Legal Proceedings 12
Item 4. Submission of Matters to a Vote of Security Holders 12
PART II
Item 5. Market for the Registrant's Common Stock and 13
Related Shareholder Matters
Item 6. Selected Financial Data 14
Item 7. Management's Discussion and Analysis of 15
Financial Condition and Results of Operations
Item 8. Financial Statements and Supplementary Data 22
Item 9. Changes and Disagreements with Accountants 22
on Accounting and Financial Disclosure
PART III
Item 10. Directors and Executive Officers of the Registrant 22
Item 11. Executive Compensation 22
Item 12. Security Ownership of Certain 23
Beneficial Owners and Management
Item 13. Certain Relationships and Related Transactions 23
Item 14. Exhibits, Financial Statement Schedules 26
and Reports on Form 8-K
For Certain Definitions of terms used herein, see page 24.
CERTAIN FACTORS THAT MAY AFFECT FUTURE RESULTS
Statements that are not historical facts contained in this report are
forward-looking statements that involve risks and uncertainties that could cause
actual results to differ from projected results. Such statements address
activities, events or developments that the Company expects, believes, projects,
intends or anticipates will or may occur, including such matters as future
availability of capital, development and exploration expenditures (including the
amount and nature thereof), drilling of wells, timing and amount of future
production of oil and gas, business strategies, operating costs and other
expenses, cash flow and anticipated liquidity, prospect development and property
acquisitions, marketing of oil and gas, and the impact of Year 2000 compliance
requirements. Factors that could cause actual results to differ materially
("Cautionary Disclosures") are described, among other places, in the Company's
prospectus dated October 2, 1997 and prospectus supplement dated October 24,
1997, as filed with the Securities and Exchange Commission, in the Marketing,
Competition, and Regulation portions of the "Business" section of this report
and under the "Management's Discussion and Analysis of Financial Condition and
Results of Operations" section of this report. Without limiting the Cautionary
Disclosures so described, Cautionary Disclosures include, among others: general
economic conditions, the market price of oil and gas, the risks associated with
exploration, the Company's ability to find, acquire, market, develop and produce
new properties, operating hazards attendant to the oil and gas business,
downhole drilling and completion risks that are generally not recoverable from
third parties or insurance, uncertainties in the estimation of proved reserves
and in the projection of future rates of production and timing of development
expenditures, potential mechanical failure or underperformance of individually
significant productive wells, the strength and financial resources of the
Company's competitors, the Company's ability to find and retain skilled
personnel, climatic conditions, labor relations, availability and cost of
material and equipment, delays in anticipated start-up dates, environmental
risks, the results of financing efforts, actions or inactions of third-party
operators of the Company's properties, regulatory developments, and third-party
Year 2000 compliance actions. All written and oral forward-looking statements
attributable to the Company or persons acting on its behalf are expressly
qualified in their entirety by the Cautionary Disclosures. The Company disclaims
any obligation to update or revise any forward-looking statement to reflect
events or circumstances occurring hereafter or to reflect the occurrence of
anticipated or unanticipated events.
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PART I
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
in the shallow waters of the Gulf of Mexico and in the Powder River and Green
River Basins of Wyoming. As of December 31, 1997, the Company's estimated net
proved reserves were 89.5 Bcf of natural gas and 8.2 MMBbl of oil, or 138.5
Bcfe, with an aggregate pre-tax present value of future net revenues of $160.2
million, using 1997 year-end prices held constant and a 10% discount rate.
In 1996, the Company changed its primary focus from its traditional areas
of operation in 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 1997, the Company has participated in drilling 14 Gulf of Mexico wells,
including nine that found apparent commercial hydrocarbons, one of which will
require a sidetrack or re-drill due to mechanical problems. The Company has
operated 11 of the 14 wells in which it has participated and has retained
working interests averaging approximately 53% at the time of drilling. As of
year-end 1997, the Company had assembled a Gulf of Mexico leasehold position
totaling 122,881 gross acres, or 84,547 net acres, with more than 30 identified
potential 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, 1997.
During 1997, the Company invested $105.6 million in oil and gas properties,
of which approximately 92% related to activities in the Gulf of Mexico.
Expenditures related to the Gulf of Mexico were for drilling eleven exploratory
wells, nine of which found apparent commercial hydrocarbons, associated
completion and development activities, acquisitions of seismic data and
exploratory leaseholds, and three acquisitions of proved properties. The proved
property acquisitions, which had an aggregate cost of approximately $49 million
excluding amounts allocated to unproved properties, increased the Company's
interests in one of its new field discoveries and established initial working
interests averaging approximately 66% in five other fields in the Gulf of
Mexico. Other investments made in 1997 were primarily for exploitation and
development of the Company's Rocky Mountain oil and gas properties. Capital
expenditures in 1997 were significantly greater than in prior years and resulted
in an 80% increase in estimated proved oil and gas reserve quantities and a 63%
increase in undeveloped Gulf of Mexico leaseholds during the year. As a result
of the large portion of 1997 capital expenditures that related to Gulf of Mexico
activities, Gulf of Mexico assets accounted for 59% of the Company's proved
reserves at the end of the year, compared to 9% at the beginning of the year,
and properties in the Gulf of Mexico contributed 75% of fourth quarter 1997
average daily net production of 43.8 MMcfe, versus 0% of the Company's average
daily net production of 11.5 MMcfe in the first quarter of the year.
See "Management's Discussion and Analysis of Financial Condition and
Results of Operations" for additional discussion regarding the Company's history
and current business activities.
BUSINESS STRATEGY
Basin's business strategy is to generate per share growth in reserves,
production, earnings and cash flow through exploration, acquisition and
development of oil and gas properties. The Company implements this strategy
through the following:
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.
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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 with substantial operating experience outside of the Gulf of Mexico
and intends to utilize this in-house capability in conjunction with regionally
specialized geoscientists employed by the Company or engaged as 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 six Landmark workstations, to better define
drilling prospects and exploitation opportunities. Basin has licensed more than
350,000 miles of conventional 2-D seismic data and approximately 250 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 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, 1997, 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. However, the Company anticipates that its capital expenditures
are likely to exceed cash flow from operations in the foreseeable future,
requiring periodic sales of assets or securities, 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 majority of the Company's gas and natural gas liquids from fields in
the Rocky Mountain region are sold under marketing arrangements where prices
received are responsive to changes in regional spot markets. These include
short-term contracts under which gas is sold at the wellhead at market-sensitive
prices, and long-term (often for the life of the lease) percentage-of-proceeds
contracts with gas processors.
KN Gas Gathering ("KNGG") purchases virtually all of the Company's Powder
River Basin gas and natural gas liquids from the Company's operated wells 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
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terms as favorable as those characterizing the KNGG sales. The Company does
not believe that the loss of KNGG as a purchaser would have a material adverse
effect on the Company.
Demand for natural gas is highly seasonal, with demand generally higher in
the colder winter months and in hot summer months. As a result, the price
received for spot market natural gas may vary significantly between seasonal
periods. To date, the Company generally has been able to sell its available
spot market natural gas at prevailing spot market prices, such that volumes sold
have not materially fluctuated seasonally. There is no assurance, however, that
the Company will be able to continue to achieve this result.
Oil from the Company's Rocky Mountain properties is generally sold under
term contracts that yield a premium over local posted prices.
Because of the well-developed transportation infrastructure and the
relatively large number of active oil and gas purchasers in the Gulf Coast area,
including in the Gulf of Mexico where the Company is conducting exploration and
acquisition activities, the Company does not anticipate that it will have
difficulty in marketing its production in this region at prevailing spot market
prices.
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.
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, 1997, 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.
REGULATION
The following discussion of regulation of the oil and gas industry is
necessarily brief and is not intended to constitute a complete discussion of the
various statutes, rules, regulations or governmental orders to which operations
of Basin may be subject.
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PRICE CONTROLS ON LIQUID HYDROCARBONS.
There are currently no federal price controls on liquid hydrocarbons
(including oil and natural gas liquids). As a result, Basin sells oil produced
from its properties at unregulated market prices.
REGULATION OF SALES AND TRANSPORTATION OF NATURAL GAS.
The transportation and sale of natural gas in interstate commerce is
regulated under the Natural Gas Act ("NGA"), the Natural Gas Policy Act of 1978
("NGPA") and regulations promulgated thereunder by the Federal Energy Regulatory
Commission ("FERC"). The Natural Gas Wellhead Decontrol Act of 1989 deregulated
all wellhead gas sales effective January 1, 1993. As a result, Basin's gas
sales are not directly regulated.
After Basin's gas is produced and sold, its interstate transportation and
resale is regulated by the FERC. The transportation and resale of natural gas
transported and resold within the state of its production is usually regulated
by the state involved. Although federal and state regulation of the
transportation and resale of Basin's natural gas does not have a material direct
impact on Basin, such regulation does have a material impact on the market for
Basin's gas and the price Basin receives for its gas.
Commencing in the mid-1980s and continuing until the present, the FERC has
adopted regulations designed to make interstate gas markets flexible and
competitive. These regulations now require interstate pipelines to transport
natural gas owned by others on a nondiscriminatory basis and have resulted in a
flexible and competitive national market for natural gas. Current gas market
conditions are a result of how the FERC has chosen to exercise its authority.
The FERC retains authority to change these regulations. Basin has no reason to
predict changes, but changes in the regulation of interstate gas transportation
and resales could have a material impact on the market for Basin's gas
production and the price Basin receives for its gas production.
The FERC has additional regulatory authority over pipelines operating on or
across the OCS under the Outer Continental Shelf Lands Act (the "OCSLA"). The
OCSLA requires all pipelines to provide open-access, non-discriminatory service.
The OCSLA allows the FERC to exempt pipeline facilities meeting a statutory
definition of "feeder lines" from the requirements of the OCSLA. The FERC has
suggested that the nature of offshore operations and its separate regulatory
authority under the OCSLA could justify broadening the definition of "gathering"
in the OCS. Gathering is exempt from regulation under the NGA. Basin cannot
predict what, if any, change in the regulation of OCS facilities will occur.
If the FERC decides that it should regulate fewer OCS facilities under the
NGA, or if it is determined that the FERC's jurisdiction over crude oil and
natural gas transportation on the OCS is more limited than previously asserted,
Basin could face higher transmission costs for its OCS natural gas production
and, possibly, reduced access to OCS transmission capacity. Upon the successful
development of its offshore exploration prospects, Basin expects to own and
operate facilities that Basin believes will be gathering lines. If the FERC
decides to make it harder to qualify for the NGA gathering exception in the OCS,
Basin's OCS facilities could be subject to regulation as interstate pipelines
and that regulation could have a material impact on Basin.
In addition to FERC regulation of interstate pipelines under the NGA,
various state commissions also regulate the rates and services of pipelines
whose operations are purely intrastate in nature. To the extent intrastate
pipelines elect to transport gas in interstate commerce under certain provisions
of the NGPA, those transactions are subject to limited FERC regulation under the
NGPA.
There are many legislative proposals pending in Congress and in the
legislatures of various states that, if enacted, might significantly affect the
oil and gas industry. Basin is not able to predict what will be enacted and
thus what effect, if any, such proposals would have on Basin.
STATE AND LOCAL REGULATION OF DRILLING AND PRODUCTION.
State regulations govern operational matters such as permits and bonds for
drilling, reclamation and plugging, spacing and pooling of wells, and reporting
requirements. The states in which Basin operates or plans to operate also have
a variety of statutes and regulations governing conservation matters, ranging
from establishment of maximum rates of production from oil and gas wells to the
proration of production to the market demand for oil and gas to the limitation
on ceiling prices for gas sold within the state. In 1991, the State of Oklahoma
enacted legislation restricting the output of certain high-volume gas wells in
response to prevailing low gas prices and the States of Texas and Louisiana have
considered similar regulatory initiatives. Any limitation substantially similar
to that enacted by Oklahoma would not have a material
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impact on Basin's current level of production, whether for oil or gas, since
Basin's wells subject to state jurisdiction do not produce at a level high
enough to meet the threshold for restriction contained in the legislation.
However, if similar legislation with lower thresholds were to be enacted in
the states in which Basin operates, or if Basin acquires or develops
properties in state waters in the Gulf of Mexico or onshore in states such as
Texas or Oklahoma having higher levels of production than the historic levels
of Basin's Rocky Mountain properties, Basin's ability to market its production
could be affected.
Also in recent years, pressure has increased in states in which the Company
has been active to increase regulation of the oil and gas industry at the local
government level. Such local regulation in general is aimed at increasing the
involvement of local governments in the permitting of oil and gas operations,
requiring additional restrictions or conditions on the conduct of operations to
reduce the impact on the surrounding community and increasing financial
assurance requirements. Accordingly, such regulation has the potential to delay
and increase the cost, or even in some cases to prohibit entirely, the conduct
of the Company's drilling activities.
ENVIRONMENTAL MATTERS.
The drilling for and production, handling, transportation and disposal of
oil and gas and by-products are subject to extensive regulation under federal,
state and local environmental laws. In most instances, the applicable regulatory
requirements relate to water and air pollution control and solid waste
management measures, permitting requirements, or restrictions on operations in
environmentally sensitive areas such as coastal zones, wetlands and wildlife
habitat. In connection with its acquisitions, Basin generally performs
environmental assessments. To the extent environmental liabilities have been
identified, such liabilities are not material or the Company has negotiated
agreements requiring the sellers of the properties to undertake the required
clean-up. Basin has assumed responsibility for some of these matters identified.
Environmental assessments have not been performed on all of Basin's properties.
To date, expenditures for environmental control facilities and for remediation
have not been significant in relation to the results of operations of Basin.
Basin believes, however, that the trend toward stricter standards in
environmental legislation and regulations is likely to continue. For instance,
efforts have been made in Congress to amend the Resource Conservation and
Recovery Act to reclassify oil and gas production wastes as "hazardous waste,"
the effect of which would be to further regulate the handling, transportation
and disposal of such waste. If such legislation were to pass, it could have a
significant adverse impact on the operating costs of Basin, as well as the oil
and gas industry in general.
The Oil Pollution Act of 1990 (the "OPA"), as amended in 1996, and
regulations thereunder impose a variety of regulations on "responsible parties"
related to the prevention of oil spills and liability for damages resulting from
such spills in United States waters. A "responsible party" includes the owner
or operator of a facility or vessel, or the lessee or permittee of the area in
which an offshore facility is located. The OPA assigns liability to each
responsible party for oil removal costs and a variety of public and private
damages. While liability limits apply in some circumstances, a party cannot
take advantage of liability limits if the spill was caused by gross negligence
or willful misconduct or resulted from violation of a federal safety,
construction or operating regulation. If the party fails to report a spill or
to cooperate fully in the cleanup, liability limits likewise do not apply. Few
defenses exist to the liability imposed by the OPA.
The OPA also imposes ongoing requirements on a responsible party in
anticipation of an oil spill event. Specifically, the OPA requires a
responsible party to maintain proof of $35,000,000 of financial responsibility
for traditional offshore facilities. The President, however, may establish a
higher degree of financial responsibility ($150,000,000) based on risk.
Offshore facilities in state waters are held to a financial responsibility of
$10,000,000 but facilities transporting, storing or otherwise handling up to
1,000 barrels of oil at any one time are exempt from these financial
responsibilities. Financial responsibility can be established through
insurance, guarantee, indemnity, surety bond, letter of credit, qualification as
a self-insurer or a combination thereof. The 1996 amendments to the OPA
eliminated third party suits against guarantors, except where a responsible
party is bankrupt or where the claimant is a federal governmental agency, and a
guarantor's total liability is limited to the amount of financial responsibility
provided. While the OPA could impose substantial additional annual costs on the
Company or otherwise materially adversely affect the Company, the impact of
these rules should not be any more adverse to the Company than it will be to
other similarly situated owners or operators in the Gulf of Mexico.
The OPA also imposes other requirements, such as the preparation of an oil
spill contingency plan. Failure to comply with ongoing requirements or
inadequate cooperation during a spill event may subject a responsible party to
civil or criminal enforcement actions.
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
who are considered to have contributed to the release of a "hazardous substance"
into the environment. These
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persons include the owner or operator of the disposal site or sites where the
release occurred and companies that disposed or arranged for the disposal of
the hazardous substances. Under CERCLA such persons or companies would be
subject to joint and several liability for the costs of cleaning up the
hazardous substances that have been released into the environment and for
damages to natural resources. It is not uncommon for neighboring landowners
and other third parties to file claims for personal injury and property damage
allegedly caused by the hazardous substances released into the environment.
New initiatives regulating the disposal of oil and gas waste are also
pending or have been enacted in certain states, including states in which Basin
conducts operations, and these various initiatives could have a similar impact
on Basin. These rules establish significant permitting, record-keeping and
compliance procedures that may require the termination of production from
marginal wells for which the cost of compliance would exceed the value of
remaining production and could lead to the incurring of significant remediation
costs for properties found to have caused groundwater contamination or other
environmental problems.
FEDERAL LEASES.
A significant percentage of the Company's operations is conducted on public
lands, both in the Rocky Mountain region and in the Gulf of Mexico. Operations
on onshore federal leases must be conducted in accordance with permits issued by
the Bureau of Land Management and are subject to a number of other regulatory
restrictions, such as winter game restrictions. Moreover, on certain federal
leases, prior approval of drillsite locations must be obtained from the
Environmental Protection Agency.
Offshore leases in the Gulf of Mexico, beyond the limits of state
ownership, are administered by the Minerals Management Service of the United
States Department of the Interior (the "MMS"). Such leases are issued through
competitive bidding, contain relatively standardized terms and require
compliance with detailed MMS regulations and orders pursuant to the OCSLA (which
are subject to change by the MMS). For offshore operations, lessees must obtain
MMS approval for exploration plans and development and production plans prior to
the commencement of such operations. In addition to permits required from other
agencies (such as the Coast Guard, the Army Corps of Engineers and the
Environmental Protection Agency), lessees must obtain a permit from the MMS
prior to the commencement of drilling. The MMS has promulgated regulations
requiring offshore production facilities located on the OCS to meet stringent
engineering, construction, safety and operational specifications. The MMS also
has regulations restricting the flaring or venting of natural gas. Similarly,
the MMS has promulgated other regulations governing the plugging and abandonment
of wells located offshore and the removal of all production facilities.
The United States Department of Transportation ("DOT"), through its Office
of Pipeline Safety, also imposes certain requirements on parties responsible for
pipelines and platforms located on the OCS. In October 1995, the MMS indicated
its intent to review all of its regulations governing offshore regulations after
the MMS and DOT completed a new Memorandum of Understanding regarding the
agencies' respective authority over offshore operations. To date, the pertinent
regulations have not been implemented.
The MMS has entered into a series of Memoranda of Understanding with other
federal agencies, such as the Environmental Protection Agency, Coast Guard, and
Occupational Safety and Health Administration, providing for the MMS to
undertake certain inspection and, in some cases, enforcement responsibility for
the respective regulatory mandates of these agencies. Those agencies do,
however, retain varying degrees of jurisdiction over OCS operations to establish
and enforce regulatory requirements.
To cover the various obligations of lessees on the OCS, the MMS generally
requires that lessees post substantial bonds or other acceptable assurances that
such obligations will be met. The cost of such bonds or other surety can be
substantial and there is no assurance that bonds or other surety can be obtained
in all cases. The Company is currently exempt from the supplemental bonding
requirements of the MMS, but there is no assurance that such exemption will be
maintained. In 1997, the MMS modified its regulations to, among other things,
(i) impose the duty on any lessee of an offshore lease to meet end-of-lease
obligations if the designated operator is unable to do so, (ii) establish joint
and several liability for plugging and abandonment of wells, removal of
platforms and other facilities, and clearance of well and platform locations,
among OCS lessees, assignees and assignors, thus creating residual liability in
certain parties for these obligations, (iii) increase the level of bond coverage
for drilling deep stratigraphic test wells and (iv) allow the MMS Regional
Director to require, on a case-by-case basis, posting of additional bonds or
other security in order to increase the amount of coverage for end-of-lease
obligations or certain other operations. These requirements could substantially
increase the Company's current bonding liabilities, and could also impact the
Company's residual liabilities, both with respect to existing leases acquired
from third parties and with respect to leases that it may acquire or dispose of
in the future.
6
<PAGE>
Under certain circumstances, such as significant uncorrected safety
violations, the MMS may require any operations on federal leases to be suspended
or terminated. Any such suspension or termination could materially and
adversely affect the Company's financial condition and operations.
The MMS has published a notice of proposed rulemaking which, if adopted,
would significantly change the current rules governing the value of crude oil
for royalty payments on onshore and offshore federal leases. The new proposed
valuation rule would retain the concept of gross proceeds for calculating
royalties on production sold to third parties in arm's-length transactions.
However, oil sold in non-arm's-length contracts would be valued using index
pricing method or other benchmarking procedures to determine a deemed arm's-
length price. The proposed rules define non-arm's-length sales to include sales
to affiliates, certain exchange transactions, sales pursuant to certain call
provisions, and other transactions. The breadth of these definitions could
cause certain sales by the Company to be impacted and could in some cases
require that it pay royalty on a deemed value higher than that which it actually
receives for its oil. As of this date, the MMS has not finalized or adopted the
proposed rule, and its impact, if any, on the Company is therefore uncertain.
TITLE TO PROPERTIES
As is customary in the oil and natural gas industry, the Company makes only
a cursory review of title to farmout acreage and to onshore undeveloped oil and
natural gas leases upon execution of contracts for acquisition of leases. Prior
to the commencement of drilling operations, a thorough title examination is
conducted and curative work is performed with respect to significant defects.
The Company performs complete reviews of title to federal and state offshore
lease blocks and onshore producing properties prior to acquisition. To the
extent title opinions or other investigations reflect material title defects,
the seller of the property, rather than the Company, is typically responsible
for curing any such title defects at its expense. If the Company were unable to
remedy or cure any title defect of a nature such that it would not be prudent to
commence drilling operations on undeveloped properties, the Company could suffer
a loss of its entire investment in the property. The Company has obtained title
opinions on substantially all of its producing properties and believes that it
has satisfactory title to such properties in accordance with standards generally
accepted in the oil and gas industry. The Company's producing properties are
mortgaged to its banks or are subject to a negative pledge in connection with
its revolving credit facility.
OPERATIONAL HAZARDS AND INSURANCE
The Company's operations are subject to the usual hazards incident to the
drilling and production of oil and gas, such as blowouts, cratering, explosions,
uncontrollable flows of oil, gas or well fluids, fires, pollution, releases of
toxic gas and other environmental hazards and risks. These hazards can cause
personal injury and loss of life, severe damage to and destruction of property
and equipment, pollution or environmental damage and suspension of operations.
Offshore operations are subject to the additional hazards of marine operations,
such as capsizing of vessels, collision and adverse weather and sea conditions.
The Company maintains insurance of various types to cover its operations.
The Company has $1,000,000 of general liability insurance and an additional
$30,000,000 of excess liability insurance. In addition, the Company maintains
operator's extra expense coverage which applies to care, custody and control of
wells drilled or completed. The Company's insurance does not cover every
potential risk associated with the drilling and production of oil and gas. In
particular, coverage is not obtainable for certain types of environmental
hazards or downhole risks. The occurrence of a significant adverse event, the
risks of which are not fully covered by insurance, could have a material adverse
effect on the Company's financial condition and results of operations.
Moreover, no assurance can be given that the Company will be able to maintain
adequate insurance in the future at rates it considers reasonable.
ABANDONMENT COSTS
Basin is responsible for costs associated with the plugging of wells, the
removal of facilities and equipment and site restoration on its oil and gas
properties, pro rata to its working interest. As of December 31, 1997, the
Company's total estimated undiscounted future abandonment costs for properties
in federal waters in the Gulf of Mexico were approximately $12.8 million. For
onshore properties, salvage values received for equipment are usually sufficient
to offset abandonment costs. Estimates of abandonment costs and their timing
may change due to many factors, including actual drilling and production
results, inflation rates, and changes in environmental laws and regulations. No
significant abandonment costs are anticipated to be incurred in 1998. Estimated
future abandonment costs are added to net unamortized historical oil and gas
property costs for purposes of computing depreciation, depletion and
amortization expense charges.
7
<PAGE>
EMPLOYEES
At December 31, 1997, Basin had 61 employees, including 15 employed in
field operations and 46 employed in its Denver headquarters or Houston division
office. None of Basin's employees are subject to a collective bargaining
agreement and Basin considers its relations with its employees to be good.
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, 1997, the estimated
pre-tax present value of future net revenues from the Company's proved reserves,
using year-end product prices held constant and a discount rate of 10%, totaled
$160,230,000 and was distributed as follows: Gulf of Mexico - 78%; Powder River
Basin - 16%; other onshore - 6%.
GULF OF MEXICO
As of December 31, 1997, the Company's estimated proved reserves in the
Gulf of Mexico were distributed among eleven fields. At that date,
approximately 71% of the Company's estimated proved reserves in the Gulf of
Mexico and 42% of the Company's total proved reserve quantities were accounted
for by five of these properties, including East Cameron Block 378, Eugene Island
Block 65, High Island Block A-568, Vermilion Blocks 329/338, and West Cameron
Blocks 45/56. The Company's other six proved properties in the Gulf of Mexico at
the end of 1997 were East Cameron Block 220, Eugene Island Block 49, Eugene
Island Block 64 S/2, Eugene Island Block 83, South Timbalier Block 146, and West
Delta Block 122. The Company's working interests in these eleven Gulf of Mexico
fields ranged from 25% to 100% and averaged approximately 63% at the end of
1997. The Company operates seven of the properties, which account for
approximately two-thirds of the Company's Gulf of Mexico proved reserves
quantities and related pre-tax present value of future net revenues at December
31, 1997.
At the end of 1997, developed reserves accounted for 91% of the Company's
total proved reserve quantities in the Gulf of Mexico and 95% of the related
pre-tax present value of future net revenues .
Eugene Island Block 65 commenced production in mid-August 1997. East
Cameron Block 220, High Island Block A-568, Vermilion Blocks 329/338, and West
Cameron Blocks 45/56 were producing or had previously produced at the time
interests in those four properties were acquired by the Company in late-November
1997. The remaining six fields were discovered in 1997 and had not yet commenced
production as of year-end. In addition to seven wells on these six properties,
two wells drilled in 1997 on High Island Block A-568 and West Cameron Block 56,
respectively, were under development for first production at the end of 1997.
As is generally the case for Gulf of Mexico properties, the Company's
properties in this area are expected to exhibit a high initial production rate
followed by a steep decline in production after a relatively short period. As a
result, since a significant portion of the Company's total proved reserves are
located in the Gulf of Mexico, the Company's reserves, production and revenues
will decline rapidly without successful exploration or acquisition activities.
POWDER RIVER BASIN
At December 31, 1997, developed reserves accounted for 61% of the Company's
total estimated proved reserve quantities in the Powder River Basin, and 78% of
the related pre-tax present value of future net revenues. Approximately 92% of
such proved reserves were concentrated in three fields: Scott, Well Draw, and
Jepson-Holler Draw. At the end of 1997, the Company owned interests in 220
producing wells and in another eight locations attributed proved undeveloped
reserves within these fields. The Jepson-Holler Draw Field was unitized in 1996
for purposes of initiating secondary recovery operations in the Shannon
formation. Water injection commenced in January 1997 and production response is
projected to be evident by late-1998. Most of the proved reserves estimated for
Jepson-Holler Draw as of December 31, 1997 were categorized as undeveloped. The
primary product produced from most of the Company's Powder River Basin
properties is oil, but many of the wells also produce liquids-rich casinghead
gas generally requiring processing for marketing. Proved reserves are
distributed broadly among the wells and locations in these fields, such that no
individual well or location accounts for a material portion of aggregate
quantities attributed to these properties. Most of the Company's producing
wells in the Powder River Basin have been online for several years and
production declines are relatively moderate and well established.
8
<PAGE>
OTHER ONSHORE
At December 31, 1997, 72% of estimated proved reserve quantities in the
Company's other onshore fields, and 82% of the related pre-tax present value of
future net revenues, were proved developed. Approximately 60% of proved reserve
quantities for these properties were associated with the Bird Canyon, Scott
Hill, and Horn Canyon fields in the Green River Basin. At the end of 1997, the
Company held interests in 10 producing wells and seven proved undeveloped
locations within these fields. Scott Hill Field produces oil, whereas the Bird
Canyon and Horn Canyon Fields produce predominantly gas. The producing wells in
these fields have been on line for several years and generally exhibit stable
performance histories, with established moderate decline rates.
Additional information related to the Company's properties is set forth
below in the balance of this section.
OIL AND GAS RESERVES
Basin engaged independent petroleum engineers, Netherland, Sewell &
Associates, Inc., to audit Basin's estimates of total proved reserves, projected
future production, and estimated future net revenues from production of proved
reserves for the Company's onshore properties as of December 31, 1997. Basin
engaged Ryder Scott Company Petroleum Engineers to prepare such estimates for
properties accounting for 66% of the Company's proved reserve quantities in the
Gulf of Mexico as of such date and to audit Basin's estimates for the remaining
offshore properties. These estimates were based upon a review of production
histories and other geologic, economic, ownership, volumetric and engineering
data. In determining the estimates of the reserve quantities that are
economically recoverable, oil and gas prices and estimated development and
production costs as of December 31, 1997 were utilized.
The following table sets forth estimates as of December 31, 1997 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.
<TABLE>
<CAPTION>
PROVED RESERVES
--------------------------------
DEVELOPED UNDEVELOPED TOTAL
<S> <C> <C> <C>
Oil (MBbls) . . . . . . . . . . . . . . . . . 4,863 3,291 8,154
Gas (MMcf) . . . . . . . . . . . . . . . . . 82,571 6,963 89,534
Total (MMcfe) . . . . . . . . . . . . . . . . 111,749 26,709 138,458
Future Net Revenue Before Income Taxes
(in thousands). . . . . . . . . . . . . . . $ 189,826 $ 31,105 $ 220,931
Present Value of Future Net Revenue Before
Income Taxes (in thousands) . . . . . . . . . $ 147,367 $ 12,863 $ 160,230
</TABLE>
The following table sets forth estimates of Basin's total proved reserves
at December 31, 1997 by geographic area of operations:
<TABLE>
<CAPTION>
PROVED RESERVES
--------------------------------
OIL GAS TOTAL
(MBbls) (MMcf) (MMcfe)
<S> <C> <C> <C>
Offshore Gulf of Mexico . . . . . . 1,798 71,036 81,824
Powder River Basin. . . . . . . . . 5,350 8,197 40,297
Other Onshore . . . . . . . . . . . 1,006 10,301 16,337
----- ------ -------
Total . . . . . . . . . . . . . . 8,154 89,534 138,458
----- ------ -------
----- ------ -------
</TABLE>
9
<PAGE>
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,
1997 were $16.34 per Bbl for oil and $2.32 per Mcf for gas. These prices are
significantly below the average prices prevailing during most of 1997, when the
Company realized average oil and gas prices of $19.07 per Bbl and $2.71 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, 1997.
Undeveloped acreage includes leasehold interests which may already have been
classified as containing proved undeveloped reserves.
<TABLE>
<CAPTION>
DEVELOPED ACREAGE(1) UNDEVELOPED ACREAGE
--------------------- -------------------
GROSS NET GROSS NET
<S> <C> <C> <C> <C>
Louisiana Offshore . . . . . . . . 46,250 30,903 64,391 45,694
Texas Offshore . . . . . . . . . . 11,520 7,680 720 270
------- ------ ------- -------
Total Offshore. . . . . . . . . . 57,770 38,583 65,111 45,964
------- ------ ------- -------
Montana. . . . . . . . . . . . . . -- -- 10,735 7,495
Utah . . . . . . . . . . . . . . . 1,842 1,065 13,633 7,323
Wyoming. . . . . . . . . . . . . . 45,219 26,234 70,448 48,024
Other Onshore. . . . . . . . . . . 1,990 851 7,727 4,230
------- ------ ------- -------
Total Onshore . . . . . . . . . . 49,051 28,150 102,543 67,072
------- ------ ------- -------
Total . . . . . . . . . . . . 106,821 66,733 167,654 113,036
------- ------ ------- -------
------- ------ ------- -------
</TABLE>
(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.
10
<PAGE>
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.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1995 1996 1997
<S> <C> <C> <C>
Production:
Oil (MBbls). . . . . . . . 1,153 564 524
Gas (MMcf) . . . . . . . . 12,833 4,776 5,509
Total (MMcfe). . . . . . . 19,751 8,160 8,653
Average Daily
Production:
Oil (Bbls) . . . . . . . . 3,160 1,540 1,435
Gas (Mcf). . . . . . . . . 35,154 13,050 15,094
Total (Mcfe) . . . . . . . 54,114 22,290 23,704
Average Sales Price
Per Unit(1):
Oil (Bbl) . . . . . . . . $ 17.12 $ 20.88 $ 19.07
Gas (Mcf). . . . . . . . . $ 1.34 $ 1.44 $ 2.71
Total (Mcfe) . . . . . . . $ 1.86 $ 2.29 $ 2.88
Production Costs Per Mcfe. . $ .59 $ .81 $ .68
</TABLE>
(1) excluding hedging effects and Section 29 tax credit income
Basin owned 292 gross (183 net) producing oil wells and 68 gross (36
net) producing gas wells as of December 31, 1997. 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.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1995 1996 1997
(IN THOUSANDS)
<S> <C> <C> <C>
Development Costs . . . . . . . $ 7,427 $ 4,472 $ 17,901
Exploration Costs. . . . . . . . 2,003 10,250 27,995
Property Aquisition Costs:
Unproved(1) . . . . . . . . . . 2,429 5,056 11,057
Proved . . . . . . . . . . . . 3,889 3,067 48,680
------- ------- --------
Total Costs Incurred . . . . . . $15,748 $22,845 $105,633
------- ------- --------
------- ------- --------
</TABLE>
(1) Excludes $4,914,000 and $1,113,000 of costs recouped through the resale of
partial interests in prospects to industry partners in 1996 and 1997,
respectively.
11
<PAGE>
DRILLING ACTIVITY
The following table sets forth the wells drilled and completed by Basin
during the periods indicated.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------
1995 1996 1997
---------- ---------- -----------
GROSS NET GROSS NET GROSS NET
<S> <C> <C> <C> <C> <C> <C>
Development:
Oil. . . . . . . . . . 4 3.9 3 2.8 5 5.0
Gas. . . . . . . . . . -- -- -- -- 1 0.6
Non-productive . . . . -- -- 1 .9 -- --
--- --- --- --- --- ---
Total. . . . . . . . 4 3.9 4 3.7 6 5.6
--- --- --- --- --- ---
--- --- --- --- --- ---
Exploratory:
Oil. . . . . . . . . . 2 1.3 -- -- -- --
Gas. . . . . . . . . . -- -- -- -- 5 3.2
Non-productive . . . . 2 1.7 3 1.4 3 1.5
--- --- --- --- --- ---
Total. . . . . . . . 4 3.0 3 1.4 8 4.7
--- --- --- --- --- ---
--- --- --- --- --- ---
</TABLE>
PRESENT ACTIVITIES
At the end of 1997, the Company was participating in three (1.1 net) Gulf
of Mexico exploratory wells that were in process. Two of these were on West
Delta Block ("WD") 122 and one was on South Timbalier Block ("ST") 146. All
three of these wells were attributed proved undeveloped reserves as of December
31, 1997. The WD 122 #1 well completed drilling in September 1997 and was
temporarily suspended. The WD 122 #2 well completed drilling in October 1997,
but was temporarily abandoned due to mechanical problems that occurred during
drilling. The Company anticipates that either the WD 122 #2 will be re-entered
at a later date to drill a sidetrack well from surface casing depth to the
original objective sands or the well will be re-drilled. The ST 146 well
completed drilling in December 1997 and was temporarily suspended pending future
completion operations and installation of production facilities.
On March 18, 1998, the Company participated in apparent winning bids for 12
tracts at the Central Gulf of Mexico lease sale held by the MMS. Such tracts
comprised 59,995 gross and 56,245 net undeveloped acres offshore Louisiana. If
all 12 tracts are awarded by the MMS, which can choose to reject all bids for a
given lease, the Company's net share of the related leasehold bonuses will total
approximately $20,358,000.
During 1998, through March 18, the Company has participated in drilling
five gross (2.1 net) exploratory wells in the Gulf of Mexico, including three
gross (1.4 net) wells that have been or are expected to be completed. The three
apparent discoveries were located, respectively, on East Cameron Block 34,
Galveston Block 213, and West Delta Block 78.
ITEM 3. LEGAL PROCEEDINGS.
The Company is not currently involved in any material legal proceedings.
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 1997.
12
<PAGE>
PART II
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, 1997 there were 178
owners of record and approximately 2,500 beneficial owners of the Company's
common stock. The following table sets forth, for the periods indicated, the
range of high and low closing prices for the common stock as reported by the
Nasdaq National Market for the last two calendar years.
<TABLE>
<CAPTION>
HIGH LOW CLOSE
<S> <C> <C> <C>
1996
First Quarter $ 5.25 $ 3.69 $ 5.13
Second Quarter $ 6.63 $ 5.00 $ 6.50
Third Quarter $ 7.50 $ 5.75 $ 7.00
Fourth Quarter $ 7.75 $ 5.63 $ 6.25
1997
First Quarter $ 7.38 $ 6.16 $ 6.88
Second Quarter $ 8.63 $ 6.50 $ 7.75
Third Quarter $17.13 $ 7.81 $16.75
Fourth Quarter $23.00 $16.75 $17.75
</TABLE>
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 cash dividends on its Common Stock and has no present plans to do so.
13
<PAGE>
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.
<TABLE>
<CAPTION>
(In thousands, except per share data)
1993 1994 1995 1996 1997
-------- ------- ------- ------- --------
<S> <C> <C> <C> <C> <C>
STATEMENTS OF OPERATIONS
DATA:
Revenue:
Oil Sales $ 13,725 $19,971 $ 19,632 $11,292 $ 9,844
Gas Sales 24,139 24,255 20,013 6,890 14,557
Gain on Sale of Assets -- -- -- 22,472 --
Interest and Other 104 161 831 1,009 319
-------- ------- ------- ------- --------
37,968 44,387 40,476 41,663 24,720
-------- ------- ------- ------- --------
Costs and expenses:
Lease Operating Expenses 7,105 8,642 8,196 4,776 4,600
Production Taxes 2,918 3,432 3,478 1,829 1,260
Depreciation, Depletion
and Amortization 12,311 18,163 17,202 7,606 10,622
General and
Administrative, Net 4,182 4,641 5,498 3,850 3,694
Interest and Other 3,160 3,618 6,929 2,272 764
Property Impairment -- -- 26,500 -- --
-------- ------- ------- ------- --------
29,676 38,496 67,803 20,333 20,940
-------- ------- ------- ------- --------
Income (Loss) Before
Income Taxes 8,292 5,891 (27,327) 21,330 3,780
Income Tax (Provision)
Benefit (3,142) (2,236) 7,784 (5,760) (1,324)
-------- ------- ------- ------- --------
Net Income (Loss) $ 5,150 $ 3,655 $(19,543) $15,570 $ 2,456
-------- ------- ------- ------- --------
-------- ------- ------- ------- --------
Basic:
Earnings (Loss) Per Share $ .67 $ .34 $ (1.82) 1.45 $ .22
Weighted Average Shares
Outstanding 7,650 10,813 10,710 10,700 11,228
Diluted:
Earnings (Loss) Per Share $ 66 $ .34 $ (1.82) $ 1.45 $ .22
Weighted Average Shares
Outstanding 7,813 10,879 10,710 10,730 11,345
BALANCE SHEET DATA (AT END
OF PERIOD):
Working Capital (Deficit) $ 106 $(5,646) $(2,211) $19,178 $(10,036)
Net Property and Equipment 116,133 165,807 134,598 54,800 149,175
Total Assets 131,520 184,855 146,651 84,957 161,959
Long-term Debt 41,819 77,199 77,172 218 11,053
Total Stockholders' Equity 67,183 72,575 53,287 68,751 121,365
</TABLE>
14
<PAGE>
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,
1997 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 activities in the shallow waters of the Gulf of Mexico and
acquisition and exploitation operations in 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, the
Company 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 the
following: (i) a smaller, lower-quality inventory of D-J Basin exploitation
projects; (ii) limited success in identifying acquisition opportunities and
viable exploration plays in the Company's other Rocky Mountain focus areas; and
(iii) liquidity constraints caused by higher debt levels without a commensurate
increase in 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. First production from Gulf of Mexico assets
was realized in August 1997 when the Company 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 through both
exploratory drilling and acquisitions and as of year-end it owned interests in
five producing properties and had nine wells under development on eight
separate lease blocks. Seven of the wells under development are projected to
commence production in the first half of 1998. The other two wells, one of
which is expected to be redrilled or sidetracked due to wellbore mechanical
problems, are not expected to commence production until 1999. As described
below under Results of Operations, the Company's net production has increased
significantly with initiation of contributions from Gulf of Mexico properties.
During 1997, the Company's capital expenditures totaled approximately $106
million, including approximately $49 million for acquisitions of proved
properties and an aggregate of $57 million for investment in exploratory
leaseholds, geological and geophysical data, exploratory drilling, completion
and development activities, and other. Over 90% of these expenditures were
associated with the Company's Gulf of Mexico operations. Capital expenditures in
1997 were funded with a combination of cash flow, working capital, borrowings
under the Company's Credit Facility, and proceeds from a public offering of
common stock. The Company closed the year with a working capital deficit of
approximately $10 million, long-term debt of $11 million, and stockholders'
equity of $121 million.
15
<PAGE>
OPERATING ENVIRONMENT
Basin's results of operations are significantly impacted by oil and gas
price levels, which are 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. Oil prices reflect
global supply and demand conditions to a greater degree, including the impact on
supply of decisions to limit production by petroleum exporting countries.
Because the Company's recent production increases have been attributable to Gulf
of Mexico properties that are predominantly gas producing, the portion of the
Company's total production that is accounted for by gas has also increased. Gas
production represented 75% of the Company's total production in the fourth
quarter of 1997, compared to 39% in the first half of the year. Although the
Company generally can not exert control over oil and gas prices it receives, it
periodically enters into fixed price sales agreements or hedging transactions to
take advantage of prices that it believes to be attractive and to reduce
volatility of net price realizations. Demand for drilling rigs and related
products and services has been relatively high during the past two years,
resulting in cost increases, occasional delays in obtaining materials and
services, and some instances of decreased quality of goods and services. Recent
conditions have been factored into the Company's planning and investment
decisions and management does not believe that such conditions will have a
material adverse impact on the timing or profitability of the Company's planned
activities unless there is substantial further deterioration in the cost or
availability of these goods and services, which is not anticipated.
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, which is not proprietary and therefore is
available to competitors, as a tool in its prospect generation. The broad and
increasing availability of this data increases the number of potential
competitors for, and tends to increase the cost of, available prospects. During
1997, the Company was successful in expanding its inventory of potential
exploratory drilling locations from approximately eight to thirty, while
drilling eleven test wells. The Company also particiated in submitting high
bids for twelve leases with identified exploratory properties at a Central Gulf
of Mexico lease sale held in March 1998 (see "PROPERTIES - Present Activities").
However, the Company faces competition for prospects from a number of
well-capitalized oil and gas companies and there is no assurance that the
Company will be able to continue to acquire interests in prospects at acceptable
costs to replace its current 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 seeks to make acquisitions of proved properties in both the
Gulf of Mexico and in selected areas onshore. During the past several years,
competition for such property packages has been intensifying and prices paid for
properties have been increasing.
The Company has initiated a review of its internal information systems for
Year 2000 transition problems and, although such review is still in progress,
believes that conversion requirements will not result in significant disruption
of the Company's business operations or have a material adverse impact on its
future liquidity or results of operations. The Company has not extensively
investigated the Year 2000 compliance of its customers, suppliers, and other
third parties with whom it has business relationships, but intends to make
selected inquiries. Compliance by such third parties is voluntary and failures
could occur, in which case there is the possibility of a material adverse impact
on the Company. However, the nature of the Company's business and its business
relationships are not such that the Company considers the potential Year 2000
compliance failure of a third party with whom it has a direct business
relationship likely to have a material adverse impact on the Company.
RESULTS OF OPERATIONS
The following table sets forth certain operating information for the three
years ended December 31, 1997. 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.
16
<PAGE>
<TABLE>
<CAPTION>
Year Ended December 31,
1995 1996 1997
-------- --------- --------
<S> <C> <C> <C>
Production:
Oil (MBbl) 1,153 564 524
Gas (MMcf) 12,833 4,776 5,509
Total Gas Equivalents (MMcfe) 19,751 8,160 8,653
Revenue (in thousands):
Oil Sales $19,632 $11,292 $ 9,844
Gas Sales $20,013 $ 6,890 $14,557
Total Oil and Gas Sales $39,645 $18,182 $24,401
Average Sales Price:
Oil (per Bbl) $17.02 $20.03 $18.80
Gas (per Mcf) $ 1.56 $ 1.44 $ 2.64
Total Gas Equivalents (per Mcfe) $ 2.01 $ 2.23 $ 2.82
Expenses (per Mcfe):
Lease Operating Expenses $ .41 $ .59 $ .53
Production Taxes $ .18 $ .22 $ .14
Depreciation, Depletion, and Amortization $ .87 $ .93 $ 1.23
General and Administrative, Net $ .28 $ .47 $ .43
</TABLE>
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.
<TABLE>
<CAPTION>
Quarter Ended March 31 June 30 Sept. 30 Dec. 31 March 31 June 30 Sept. 30 Dec. 31
1996 1996 1996 1996 1997 1997 1997 1997
-------- ------- -------- -------- -------- ------- --------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
Production:
Oil (MBbl) 216 152 98 98 106 103 147 168
Gas (MMcf) 2,458 1,465 429 424 403 399 1,688 3,019
Total Gas Equivalents
(Mmcfe) 3,754 2,377 1,017 1,012 1,039 1,017 2,570 4,027
Revenue (in thousands):
Oil Sales $ 3,875 $ 3,164 $ 2,064 $ 2,189 $ 2,155 $ 1,828 $ 2,737 $ 3,124
Gas Sales $ 3,611 $ 1,932 $ 522 $ 825 $ 1,082 $ 689 $ 4,139 $ 8,647
Total Oil and Gas Sales $ 7,486 $ 5,096 $ 2,586 $ 3,014 $ 3,237 $ 2,517 $ 6,876 $11,771
Average Sales Price:
Oil (per Bbl) $ 17.94 $ 20.84 $ 21.10 $ 22.31 $ 20.41 $ 17.73 $ 18.59 $ 18.62
Gas (per Mcf) $ 1.47 $ 1.32 $ 1.22 $ 1.95 $ 2.69 $ 1.73 $ 2.45 $ 2.86
Total Gas Equivalents
(per Mcfe) $ 1.99 $ 2.14 $ 2.54 $ 2.98 $ 3.12 $ 2.47 $ 2.67 $ 2.92
Expenses (per Mcfe):
Lease Operating Expenses $ 0.45 $ 0.56 $ 0.81 $ 0.94 $ 1.02 $ 0.96 $ 0.40 $ 0.38
Production Taxes $ 0.19 $ 0.20 $ 0.28 $ 0.34 $ 0.35 $ 0.27 $ 0.10 $ 0.09
Depreciation, Depletion,
and Amortization $ 0.89 $ 0.89 $ 1.06 $ 1.04 $ 1.12 $ 1.21 $ 1.16 $ 1.30
General and
Administrative, Net $ 0.32 $ 0.43 $ 0.79 $ 0.83 $ 0.76 $ 0.80 $ 0.33 $ 0.31
</TABLE>
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 combined with a 6% decrease in oil prices to yield a net
26% increase in revenue per net equivalent unit produced, from $2.23 per Mcfe in
1996 to $2.82 per Mcfe in 1997. 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, as reflected in the table above, due to the D-J Sales in March and
June 1996 and the commencement of Gulf of Mexico production in August 1997. The
increases in the second half of 1997 were largely attributable to Eugene Island
Block 65, which produced 4,087 net MMcfe between mid-August and the end of the
year. The only other net production obtained from Gulf of Mexico assets in 1997
was 475 net MMcfe in December from four properties acquired in late-November.
17
<PAGE>
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. 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% in 1997, to $0.53, 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, as shown in the table above,
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,
as reflected in the table above.
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 borrowing 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.
1996 COMPARED TO 1995
REVENUE. Oil and gas sales for 1996 declined by $21.5 million, or 54%, to
$18.2 million, due largely to declines in oil and gas production. An 18%
increase in oil prices combined with an 8% decrease in gas prices to yield a net
11% increase in revenue per net equivalent unit produced, from $2.01 per Mcfe in
1995 to $2.23 per Mcfe in 1996. Production declined by 59% in net equivalent
units, from 19,751 MMcfe in 1995 to 8,160 MMcfe in 1996. This large decrease in
production was primarily attributable to asset sales consummated in 1995 and
1996, including the D-J Sales closed in the
18
<PAGE>
first half of 1996, in which properties accounting for approximately 70% of
the Company's production at the time were sold. The decrease also reflects
natural production declines outside of the D-J Basin, the Company's net
production declined by 711 MMcfe, or 14%, from 4,950 MMcfe in 1995 to 4,239
MMcfe in 1996. The higher oil and gas sales reported for 1995 also reflect
recognition of $2.9 million of gas revenue for payments received with respect
to transferred Section 29 tax credits, with no comparable amount recorded in
1996.
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
in 1995 was primarily derived from a small processing facility that was
decommissioned late in the year. Other revenue reported in 1996 was mostly
interest income on cash equivalents held after the second D-J Sale transaction.
LEASE OPERATING EXPENSES. Lease operating expenses for 1996 were $4.8
million, a decrease of $3.4 million, or 42%, compared to 1995. Lease operating
costs per Mcfe produced during 1996 averaged $.59 compared to $.42 in 1995.
These higher costs per Mcfe were caused primarily by the increased portion of
the Company's total active wells that were oil wells, with typically higher unit
operating costs, following the D-J Sales.
PRODUCTION TAXES. Production taxes for 1996 were lower by $1.6 million, or
47%, than in the prior year. However, such taxes were 10.1% of oil and gas sales
in 1996 compared to 8.8% in 1995 because a greater portion of production in 1996
occurred in higher-tax jurisdictions.
DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and
amortization expense decreased by $9.6 million, or 56%, in 1996 to $7.6 million.
The decrease was primarily attributable to the lower production volumes in 1996
as compared to 1995. The depletion rate of $0.82 per Mcfe produced in 1996 was
slightly lower than the $0.84 per Mcfe average depletion rate during 1995.
PROPERTY IMPAIRMENT. During 1995, the Company recognized a property
impairment charge of $26.5 million as the result of the capitalized costs of its
oil and gas properties exceeding a "ceiling" on such costs computed in
accordance with prescribed accounting guidelines. The third-quarter charge was
associated with historically low gas prices in the Rocky Mountain region at the
time.
GENERAL AND ADMINISTRATIVE EXPENSES, NET. General and administrative
expenses decreased by $1.6 million, or 30%, in 1996 to $3.9 million. The
decrease resulted primarily from staff reductions made during the second half of
1995 and in mid-1996 in conjunction with the D-J Sales, and partially due to
reductions in office rent expense as a result of relocating and decreasing the
size of the Company's corporate headquarters.
INTEREST AND OTHER EXPENSES. Interest expense for 1996 totaled $2.3
million, representing a decrease of $4.2 million, or 65%, compared to 1995. The
variance was attributable to a decrease in average borrowings after the D-J
Sales, partially offset by an increase in the Company's average effective
interest rate. During 1996, the Company had average borrowings of $28.2 million
and an average interest rate of 8.0%, compared to average borrowings of $78.8
million and an average interest rate of 7.3% in 1995. Substantially all of the
borrowings in both years were under the Credit Facility.
INCOME TAX PROVISION/BENEFIT. Differences between the income tax provision
for 1996 and the income tax benefit recorded for 1995, and related amounts that
would be calculated by applying statutory income tax rates to income before
income taxes for each year, are due primarily to the reversal in 1996 of a $2.2
million deferred tax asset valuation allowance established in 1995.
LIQUIDITY AND CAPITAL RESOURCES
Historically, the Company's principal sources of capital have been cash
flow from operations, a revolving line of credit established with a group of
banks, 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.
Through the D-J Sales, the Company realized proceeds of approximately
$123.5 million in two transactions closed in March and June 1996. A portion of
these proceeds was used to repay substantially all of the Company's long-term
debt and at the end of 1996 the Company had $19.2 million of net working
capital, including $22.0 million of cash and equivalents, and long-term debt of
$0.2 million.
19
<PAGE>
During the fourth quarter of 1997, the Company realized net proceeds of
approximately $50 million from the sale of 2.875 million shares of common stock
through an underwritten public offering.
The Company's oil and gas capital expenditures during 1997 totaled
approximately $105.6 million. Net cash provided by operations before changes in
working capital totaled $15.3 million. The remainder of 1997 capital
expenditures was funded primarily through borrowings under the Credit Facility,
proceeds from the stock offering, and reductions in net working capital. The
Company closed 1997 with a working capital deficit of approximately $10.0
million, long-term debt of $11.1 million, and stockholders' equity of $121.4
million.
At the end of 1997, borrowings under the Company's Credit Facility totaled
$11 million, leaving $34 million of unutilized capacity under the line of
credit, which was established at $45 million as of November 1, 1997. Since the
November 1, 1997 borrowing base determination, the Company has increased the
value of its proved oil and gas reserves through a $31.3 million acquisition
(before purchase price adjustments) and drilling and development activities, and
management anticipates that the borrowing base will be increased from the
current level at the time of the next redetermination, which is scheduled to
occur April 15, 1998.
The Company has established a preliminary budget of $80 million for
exploration and development in 1998, compared to approximately $57 million
invested in such activities in 1997. This budget is subject to revision during
the year to reflect future developments. Acquisitions of properties with proved
and probable reserves are also pursued as an integral part of the Company's
overall business strategy, but are not budgeted.
The Company's average daily net oil and gas production in the fourth
quarter of 1997 was 286% greater than in the first half of the year, and net
cash provided by operations before working capital changes increased from an
average of $0.8 million per quarter in the first half of the year to $8.7
million in the fourth quarter. Further increases in production are projected for
1998, primarily from properties with proved nonproducing reserves at the end of
1997 that are expected to commence production in 1998. Factoring in these
projected increases, management believes that its projected cash flow from
operations and borrowing capacity will be sufficient to fund the Company's
operations and capital expenditures through the end of 1998, unless the Company
consummates a substantial acquisition or significantly increases its budget for
drilling activities during the period.
PRODUCTION AND CASH FLOW. The properties included in the D-J Sales
consummated in the first half of 1996 represented approximately 70% of the
Company's estimated proved oil and gas reserves and production at the time. In
each of the next four fiscal quarters after the divestitures (covering the
period from July 1, 1996 through June 30, 1997), the Company's net production of
oil and gas was approximately 1,020 MMcfe, or an average of 11.2 MMcfe per day.
For the same period, net cash provided by operations before working capital
changes ranged from $0.4 million to $2.2 million per quarter and averaged $1.3
million per quarter, varying primarily with oil and gas price levels. The flat
oil and gas production during this period reflected modest capital expenditures
on Rocky Mountain exploitation projects that offset natural declines on
producing properties. More significant investments were made in Gulf of Mexico
exploration, development, and acquisition activities that did not begin to
impact production and cash flow until the middle of the third quarter of 1997.
During the quarter ended December 31, 1997, the Company's net production
increased to 4,026 MMcfe, or approximately 43.8 MMcfe per day, and net cash flow
from operations before changes in working capital increased to $8.7 million,
primarily due to production from two wells that the Company drilled and
completed earlier in the year on Eugene Island Block 65. From commencement of
production in mid-August 1997 through December 31, 1997, combined net production
from these two wells averaged approximately 28.2 MMcfe per day.
Based primarily on the estimates reflected in the Company's year-end 1997
reserve reports, the Company anticipates that its net production in 1998 will be
more than triple its net production during 1997 of 8,653 MMcfe. This is
attributable primarily to seven Gulf of Mexico wells with proved nonproducing
reserves at the end of 1997 that were expected to commence production at various
times during 1998. The Company's average working interest in these seven wells
is approximately 58%. Production in 1998 should also include contributions
during the full period from four producing properties acquired in late-November
1997. Partially offsetting these additions will be expected lower production
from Eugene Island Block 65, due to natural depletion-related declines and to
mechanical impediments that may be remediable, but which reduced average daily
net production on the property by approximately 6 MMcfe beginning mid-December
1997.
The Company expects that its future net cash flow will be determined
substantially by production levels and oil and gas prices. Certain costs per
unit of production have significantly improved recently as the Company has
commenced production in the Gulf of Mexico and are expected to continue to
improve as scheduled increases in Gulf of Mexico production occur. Production
taxes are not applicable to properties in federal waters. Lease operating
expenses per unit tend
20
<PAGE>
to be significantly lower in the Gulf of Mexico than for the Company's Rocky
Mountain properties, especially for flush production from relatively new Gulf
of Mexico wells, and the Company does not expect its general and
administrative expenses to increase proportionately as Gulf of Mexico
production increases. As a result, net cash provided by operations is expected
to increase by a greater percentage than production volumes, given an
assumption of constant or rising oil and gas prices.
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.
As of February 12, 1998, Basin had entered into the following crude oil and
natural gas price swap or collar arrangements covering the period beginning
January 1, 1998:
<TABLE>
<CAPTION>
Bbls or Mcf Average Price
Product Per Month or Collar Range Time Period
- ------------ ------------- --------------- -----------
<S> <C> <C> <C>
Entered into on or prior
to December 31, 1997:
Crude Oil 10,000 $ 23.50 1/98
Crude Oil 10,000 $ 21.30 1/98-10/98
Natural Gas 450,000 $ 2.10-$ 2.54 1/98-04/98
Entered into subsequent
to December 31, 1997:
Natural Gas 1,200,000 $ 2.30 3/98
Natural Gas 1,350,000 $ 2.29 4/98
Natural Gas 1,050,000 $ 2.34 5/98-09/98
</TABLE>
CREDIT FACILITY. The Credit Facility with a bank group led by NationsBank
of Texas, N.A. provides for the interest rate on the Company's borrowings to be
determined by reference to either NationsBank's prime rate or LIBOR, at the
Company's election. A varying spread of 0% to 0.5% is added to the prime rate,
or 0.625% to 1.25% is applied to LIBOR, based upon the Company's
debt-to-capitalization ratio at the time. The Credit Facility provides for
borrowings to be revolving loans until August 1, 1999, at which time the
outstanding balance will be converted into a four-year amortizing term loan
unless the Credit Facility has been amended to extend the revolving period. The
borrowing base under the Credit Facility, established at $45 million as of
November 1, 1997, is scheduled to be redetermined as of April 15, 1998 and
generally at six-month intervals thereafter until converted into a term loan.
Since the November 1, 1997 borrowing base determination, the Company has
increased its proved oil and gas reserves through an acquisition and drilling
activities, and management anticipates that the borrowing base will be increased
from the current level at the time of the next redetermination. At December 31,
1997, the principal balance outstanding under the facility was $11 million, with
a weighted average interest rate of 6.7%. The Credit Facility 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 Facility, certain of the Company's onshore
properties are subject to mortgages in favor of the banks and the Company's
remaining properties are subject to a negative pledge.
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. The Company's acquisition, development, and
exploitation activities target opportunities in the vicinity of the Company's
Gulf of Mexico exploration operations, in the Rocky Mountain region where Basin
has a substantial existing base of proved reserves and producing wells, and in
certain other major domestic producing basins where Basin 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 1997 totaled approximately $106
million. Approximately $49 million of this amount was used for acquisitions of
proved properties and the remaining $57 million was used primarily for
exploration and development activities, including investments in prospect
leaseholds and geological and geophysical data, exploratory drilling, and
completion and development activities. Almost 92% of these expenditures were
associated with the Company's operations in the Gulf of Mexico, where the
Company added an estimated 83 Bcfe of proved oil and gas reserves from
extensions, discoveries, and purchases of reserves in-place, and significantly
increased its inventory of exploratory prospects, in 1997. Activities in the
Gulf of Mexico during 1997 included three acquisitions of proved properties and
participation in eleven exploratory wells, eight of which have been or are
expected to be completed as producers. One of the three wells that
21
<PAGE>
will not be completed also encountered apparent commercial hydrocarbons but
was lost due to mechanical problems and may be sidetracked or redrilled.
Expenditures outside of the Gulf of Mexico were primarily for exploitation and
development of the Company's proved properties in the Rocky Mountain region.
The Company currently estimates that its capital expenditures for
exploration and development in 1998 will be approximately $80 million. This
budget primarily provides for: participation in an estimated nine net (15 to 20
gross) exploratory wells in the Gulf of Mexico; development of six prospect
discoveries made in the Gulf of Mexico in the second half of 1997; exploitation
and development of five Gulf of Mexico properties acquired last year, including
two wells drilled in 1997 that were under development at year-end; development
of assumed 1998 prospect discoveries; investments in seismic data and prospect
leaseholds (including $20.4 million provided for apparent winning bids at the
Central Gulf of Mexico lease sale held March 18, 1998; see "PROPERTIES - Present
Activities"); and continued exploitation of the Company's Rocky Mountain
properties. Although several locations for planned 1998 exploratory drilling
have been identified and other potential locations are held in inventory, a
significant portion of the anticipated 1998 exploration budget is currently
unallocated.
The Company also intends to continue to pursue acquisitions of properties
with proved and probable reserves as an integral part of the Company's overall
business strategy, with the expectation that these efforts will result in
potentially significant investment activity.
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. As a
result, actual capital expenditures may vary significantly from current
expectations.
The Company may significantly increase its capital expenditure budget for
1998 to respond to drilling opportunities that develop during the year in the
Gulf of Mexico or potentially in new onshore focus areas, 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. In such
instance, the Company may consider raising additional capital through issuance
of debt and/or equity securities.
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. CHANGES AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The information required by this item is incorporated by reference from the
sections entitled "Management" and "Disclosure of Filings by Insiders" in the
Company's definitive Proxy Statement for its 1998 Annual Meeting of Stockholders
(the "Proxy Statement") to be filed with the Securities and Exchange Commission
no later than April 30, 1998.
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.
22
<PAGE>
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information required by this item is incorporated by reference from the
section entitled "Security Ownership of Certain Beneficial Owners and
Management" in the Proxy Statement.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The information required by this item is incorporated by reference from the
section entitled "Certain Relationships and Other Transactions" in the Proxy
Statement.
23
<PAGE>
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.
24
<PAGE>
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.
25
<PAGE>
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules
PAGE
Report of Independent Public Accountants . . . . . . . . . . . . . . . . . 27
Consolidated Balance Sheets as of December 31, 1996 and 1997 . . . . . . . 28
Consolidated Statements of Operations for the years ended
December 31, 1995, 1996, and 1997. . . . . . . . . . . . . . . . 29
Consolidated Statements of Cash Flow for the years
ended December 31, 1995, 1996 and 1997 . . . . . . . . . . . . . 30
Consolidated Statements of Changes in Stockholders' Equity
for the years ended December 31, 1995, 1996 and 1997 . . . . . . 31
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . 32
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.
26
<PAGE>
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, 1997 and 1996, 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, 1997.
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, 1997 and 1996, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 1997, in conformity with generally accepted
accounting principles.
ARTHUR ANDERSEN LLP
Denver, Colorado,
February 12, 1998.
27
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
December 31 (in thousands, except share data) 1996 1997
- -------------------------------------------------------------------------
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and Equivalents $ 22,023 $ 531
Accounts Receivable 5,108 8,348
Stockholder Note Receivable 559 --
Prepaids and Other 2,203 3,805
-------- --------
29,893 12,684
-------- --------
PROPERTY AND EQUIPMENT, at cost:
Oil and Gas Properties, Under the Full Cost
Method of Accounting -
Proved 78,641 177,704
Unproved 9,822 15,669
Less Accumulated Depreciation, Depletion and
Amortization (36,581) (46,284)
-------- --------
51,882 147,089
Furniture and Equipment, Net 2,918 2,086
-------- --------
54,800 149,175
OTHER ASSETS 264 100
-------- --------
$ 84,957 $161,959
-------- --------
-------- --------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts Payable $ 2,724 $ 8,087
Accrued Liabilities 4,745 12,067
Accrued Ad Valorem Taxes 2,040 2,394
Income Taxes Payable 1,000 19
Current Portion of Long-Term Debt 206 153
-------- --------
10,715 22,720
LONG-TERM DEBT, net of current portion 218 11,053
OTHER LONG-TERM OBLIGATIONS 513 266
DEFERRED INCOME TAXES 4,760 6,555
COMMITMENTS AND CONTINGENCIES (Note 5)
STOCKHOLDERS' EQUITY:
Preferred Stock, Par Value $.01 Per Share;
10,000,000 Shares Authorized, No Shares
Issued and Outstanding -- --
Common Stock, $.01 Par Value, 50,000,000
Shares Authorized, 10,757,000 and 13,833,000
Shares Issued Respectively 108 138
Additional Paid-In Capital 59,219 110,627
Retained Earnings 9,556 12,012
Common Stock Held In Treasury, At Cost,
56,000 and 120,000 Shares, Respectively (132) (1,412)
-------- --------
68,751 121,365
-------- --------
$ 84,957 $161,959
-------- --------
-------- --------
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
28
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
For the years ended December 31
(in thousands, except per share data) 1995 1996 1997
- ----------------------------------------------------------------------------
<S> <C> <C> <C>
REVENUE:
Oil Sales $ 19,632 $11,292 $ 9,844
Gas Sales 20,013 6,890 14,557
Gain On Sale of Assets -- 22,472 --
Interest and Other 831 1,009 319
-------- ------- -------
40,476 41,663 24,720
-------- ------- -------
COSTS AND EXPENSES:
Lease Operating Expenses 8,196 4,776 4,600
Production Taxes 3,478 1,829 1,260
Depreciation, Depletion, and Amortization 17,202 7,606 10,622
General and Administrative, Net 5,498 3,850 3,694
Interest and Other 6,929 2,272 764
Property Impairment 26,500 -- --
-------- ------- -------
67,803 20,333 20,940
-------- ------- -------
INCOME (LOSS) BEFORE INCOME TAXES (27,327) 21,330 3,780
INCOME TAX (PROVISION) BENEFIT 7,784 (5,760) (1,324)
-------- ------- -------
NET INCOME (LOSS) $(19,543) $15,570 $ 2,456
-------- ------- -------
-------- ------- -------
BASIC:
Earnings (Loss) Per Share $ (1.82) $ 1.45 $ .22
Weighted Average Shares Outstanding 10,710 10,700 11,228
DILUTED:
Earnings (Loss) Per Share $ (1.82) $ 1.45 $ .22
Weighted Average Shares Outstanding 10,710 10,730 11,345
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
29
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOW
<TABLE>
<CAPTION>
For the years ended December 31 (in thousands) 1995 1996 1997
- ------------------------------------------------------------------------------------------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss) $(19,543) $ 15,570 $ 2,456
Adjustments To Reconcile Net Income (Loss)
To Net Cash Provided By Operating Activities -
Gain On Sale of Assets -- (22,472) --
Depreciation, Depletion and Amortization 17,202 7,606 10,622
Deferred Income Tax Expense (Benefit) (7,784) 4,760 1,795
Property Impairment 26,500 -- --
Stock Compensation Expense 302 98 439
Amortization of Debt Issuance Costs 373 118 --
Other -- -- (15)
Changes In Operating Assets and Liabilities -
Decrease (Increase) In -
Restricted Cash ( 75) 578 --
Receivables 2,594 1,664 (3,188)
Prepaids and Other 206 (1,861) (1,438)
(Decrease) Increase In -
Accounts Payable and Accrued Liabilities (6,947) 103 5,692
Ad Valorem Taxes and Other (1,073) (2,255) 107
Unearned Income (1,435) -- --
Income Taxes Payable -- 1,000 (981)
-------- -------- --------
Net Cash Provided By Operating Activities 10,320 4,909 15,489
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital Additions (17,782) (27,741) (98,245)
Proceeds From Sale of Property and Equipment 3,941 125,625 195
Asset Sale Transaction Costs -- (5,257) --
-------- -------- --------
Net Cash Provided By (Used In) Investing Activities (13,841) 92,627 (98,050)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds From Notes Payable and Long-Term Debt 4,937 8,594 53,000
Principal Payments On Notes Payable (5,150) (85,517) (42,218)
Proceeds From Sale of Stock, Net -- 84 50,320
Purchase of Treasury Stock and Options (47) (287) (33)
-------- -------- --------
Net Cash Provided By (Used In) Financing Activities (260) (77,126) 61,069
-------- -------- --------
INCREASE (DECREASE) IN CASH AND EQUIVALENTS (3,781) 20,410 (21,492)
CASH AND EQUIVALENTS, Beginning of Year 5,394 1,613 22,023
-------- -------- --------
CASH AND EQUIVALENTS, End of Year $ 1,613 $ 22,023 $ 531
-------- -------- --------
-------- -------- --------
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash Paid For Interest $ 6,111 $ 2,327 $ 637
Cash Paid For Taxes $ -- $ -- $ 981
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
30
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
For the years ended December 31, 1995, 1996 and 1997 (in thousands)
<TABLE>
<CAPTION>
Retained
Common Stock Additional Treasury Stock Earnings
................ Paid-In .................. (Accumulated Stockholders'
Shares Amount Capital Shares Amount Deficit) Equity
------ ------ ---------- ------ ------ ------------ -------------
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCES, December 31, 1994 10,692 $ 107 $ 58,986 (13) $ (47) $ 13,529 $ 72,575
Purchase of Treasury Stock -- -- -- (19) (47) -- (47)
Issuance and Vesting of Restricted
Stock and Stock Options 32 -- 302 -- -- -- 302
Net Loss -- -- -- -- -- (19,543) (19,543)
------ ----- -------- ---- ------- -------- --------
BALANCES, December 31, 1995 10,724 107 59,288 (32) (94) (6,014) 53,287
Purchase of Treasury Stock
and Options -- -- (250) (24) (38) -- (288)
Issuance and Vesting of Restricted
Stock and Stock Options 33 1 181 -- -- -- 182
Net Income -- -- -- -- -- 15,570 15,570
------ ----- -------- ---- ------- -------- --------
BALANCES, December 31, 1996 10,757 108 59,219 ( 56) (132) 9,556 68,751
Issuance of Common Stock 3,001 30 51,340 -- -- -- 51,370
Common Stock Offering Costs -- -- (499) -- -- -- (499)
Purchase of Treasury Stock -- -- -- (64) (1,280) -- (1,280)
Issuance and Vesting of Restricted Stock 75 -- 567 -- -- -- 567
Net Income -- -- -- -- -- 2,456 2,456
------ ----- -------- ---- ------- -------- --------
BALANCES, December 31, 1997 13,833 $ 138 $110,627 (120) $(1,412) $ 12,012 $121,365
------ ----- -------- ---- ------- -------- --------
------ ----- -------- ---- ------- -------- --------
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
31
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION AND OPERATIONS - The consolidated financial statements include
the financial statements of Basin Exploration, Inc. and its wholly owned
subsidiaries, (collectively referred to as "Basin" or the "Company"). Basin, as
operator of jointly owned oil and gas properties, sells a significant amount of
such production to certain major customers (see Note 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. Proceeds from sales of oil and gas properties are credited to the full
cost pool with no gain or loss recognized unless such adjustments would
significantly alter the relationship between capitalized costs and proved
reserves of oil and gas.
If capitalized costs, net of amortization and related deferred taxes,
exceed the full cost ceiling, the excess would be expensed in the period such
excess occurs. The full cost ceiling includes an estimate of the discounted
value of future net revenues attributable to proven reserves, using various
assumptions and parameters consistent with promulgations of the Securities and
Exchange Commission. The full cost ceiling may be particularly sensitive to
changes in prevailing oil and gas sales prices or forecast production rates. The
Company recognized $26,500,000 of such impairment at September 30, 1995.
The Company invests in unevaluated oil and gas properties and related
assets for the purpose of future exploration for proved reserves. The costs of
such assets are included in unproved oil and gas properties at the lower of cost
or estimated fair market value.
FURNITURE AND EQUIPMENT - Furniture and equipment is depreciated over
estimated useful lives of five to seven years. Maintenance and repair costs are
expensed as incurred.
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.
32
<PAGE>
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
generally placed with major financial institutions or with counterparties of
high credit quality that the Company believes are minimal credit risks, may take
the form of futures contracts, swaps or options. The oil and gas 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.
As of February 12, 1998, the Company was a party to product swap or collar
arrangements for 1998 as follows:
<TABLE>
<CAPTION>
Average
Bbls or Mcf Fixed Price or
Product Per Month Collar Range Time Period
- --------------- ------------ ---------------- ------------
<S> <C> <C> <C>
Entered into on or prior to
December 31, 1997:
Crude Oil 10,000 $ 23.50 1/98
Crude Oil 10,000 $ 21.30 1/98-10/98
Natural Gas 450,000 $2.10-$2.54 1/98-04/98
Entered into subsequent to
December 31, 1997:
Natural Gas 1,200,000 $ 2.30 3/98
Natural Gas 1,350,000 $ 2.29 4/98
Natural Gas 1,050,000 $ 2.34 5/98-09/98
</TABLE>
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, 1997, 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 $350,000 to terminate the then-existing arrangements on December
31, 1997. 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 be
realized by the Company in 1998.
The Company recognized a reduction in oil revenue of $115,000, $480,000,
and $144,000 under hedging agreements in 1995, 1996 and 1997, respectively. The
Company recognized a reduction in gas revenue of $383,000 under hedging
agreements in 1997.
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 to purchase common stock. All options to
purchase common shares were excluded from the computation of diluted earnings
per share in 1995 because they were antidilutive as a result of the Company's
net loss in that year. 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.
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.
33
<PAGE>
(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, for an aggregate sales price of $123,500,000, effective January 1,
1996. Combined, these transactions resulted in Basin selling its interests in
approximately two-thirds of its producing wells and 70% of its proved oil and
gas reserves at December 31, 1995. Because the second transaction constituted
the sale of a significant portion of the Company's total oil and gas reserves
which would significantly alter the relationship between the Company's
capitalized costs and its proved reserves, net capitalized costs of oil and gas
properties were allocated between the reserves sold and retained based upon
their estimated relative reserve quantities as of June 7, 1996 and a resulting
gain of approximately $22,500,000 was recognized. A portion of the proceeds from
the sales was used to payoff all outstanding bank debt and residual proceeds,
net of transaction costs, were invested in short-term interest bearing cash
equivalents until redeployed into oil and gas properties. 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.
("Midcon") on November 26, 1997. The purchase price was approximately $31.3
million, subject to normal post-closing adjustments. Basin was the high bidder
at a bankruptcy court proceeding conducted to sell such assets. The principal
assets acquired were working interests in six federal outer continental shelf
blocks in the Gulf of Mexico, and the related platforms and production
facilities. Approximately $5 million of the purchase price was attributed to
prospective drilling and recompletion locations. The acquisition has been
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 consummation date. The following summarized unaudited pro
forma financial information assumes the acquisition had occurred on January 1 of
each year. The pro forma data is for informational purposes only and is not
necessarily indicative of the results of operations which would actually have
occurred had the transaction been consummated on January 1 or which may occur in
the future due to several factors, including, but not limited to, commencement
of production from new wells that has occurred during or subsequent to the
periods presented.
<TABLE>
<CAPTION>
Year Ended December 31,
(in thousands, except per share amounts) 1996 1997
------- -------
<S> <C> <C>
Revenue $52,309 $33,079
Net Income (Loss) 13,152 (574)
Earnings (Loss) Per Share:
Basic 1.23 (0.05)
Diluted 1.23 (0.05)
</TABLE>
(3) LONG-TERM DEBT
<TABLE>
<CAPTION>
December 31,
(in thousands) 1996 1997
----- -------
<S> <C> <C>
Revolving Credit Facility $ 0 $11,000
Other Notes 424 206
----- -------
424 11,206
Less: Current Portion (206) (153)
----- -------
Long-term Debt, Net of Current Portion $ 218 $11,053
----- -------
----- -------
</TABLE>
On August 6, 1996, the Company entered into an Amended and Restated Credit
Agreement (the "Credit Facility") with its existing bank group. The Credit
Facility provides for the interest rate on borrowings to be determined by
reference to the prime rate or LIBOR, at the Company's election. A varying
spread of 0% to 0.5% is added to the prime rate, or 0.625% to 1.25% is applied
to LIBOR, based upon the Company's applicable debt-to-capitalization ratio at
the time. The Credit Facility provides for borrowings to be revolving loans
until August 1, 1999, at which time the outstanding balance will be converted
into a four-year amortizing term loan unless the Credit Facility has been
amended to extend the revolving period. The borrowing base under the Credit
Facility, established at $45,000,000 in November 1997, is scheduled to be
redetermined as of April 15, 1998 and generally at six-month intervals
thereafter until converted into a term loan. The Credit
34
<PAGE>
Facility 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 Facility,
certain of the Company's onshore 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 Facility at December 31, 1997 was 6.7%.
<TABLE>
<S> <C>
Debt is payable as follows (in thousands):
1998 $ 153
1999 53
2000 688
2001 2,750
2002 2,750
Thereafter 4,812
-------
$11,206
-------
-------
</TABLE>
(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. The
Company may, at its discretion, make additional contributions to the Plan. The
Company expensed $195,000, $96,000, and $183,000, with respect to the Plan for
the years ended December 31, 1995, 1996 and 1997, respectively.
STOCK PLAN - Under the Company's Employees' Equity Incentive Plan and
Non-Employee Directors' Stock Option Plan, officers, key employees, consultants
and directors of the Company are eligible to receive incentive stock options,
non-qualified stock options, 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, 1997, a total of approximately
1,300,000 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
869,000 shares of the Company's common stock are subject to such plans as of
December 31, 1997, including 95,500 nonvested shares of restricted stock and
performance shares and 773,500 outstanding stock options.
The following table summarizes the changes in stock options:
<TABLE>
<CAPTION>
Year Ended December 31,
1995 1996 1997
-------- -------- -------
<S> <C> <C> <C>
Balance, beginning of period 541,833 702,500 649,000
Granted 265,000 252,500 202,500
Exercised -- (33,500) (78,000)
Forfeited/Canceled (104,333) (272,500) --
-------- -------- -------
Balance, end of period 702,500 649,000 773,500
-------- -------- -------
-------- -------- -------
</TABLE>
Additional information regarding the outstanding options at December 31, 1997,
is as follows:
<TABLE>
<CAPTION>
Range of Number of Weighted Weighted Average Number of Weighted
Exercise Prices Options Average Remaining Life Options Average
Per Share Outstanding Exercise Price in Years Exercisable Exercise Price
--------- ----------- -------------- -------- ----------- --------------
<S> <C> <C> <C> <C> <C>
$13.25 - $ 20.38 119,000 $15.71 6.9 51,500 $14.35
$ 7.63 - $ 11.00 165,000 $ 9.64 5.4 115,000 $ 9.44
$ 5.13 - $ 7.00 257,500 $ 6.19 8.6 79,167 $ 6.04
$ 3.88 - $ 4.94 232,000 $ 4.39 8.1 97,833 $ 4.42
------- ------ --- ------- ------
773,500 $ 7.85 7.4 343,500 $ 7.96
------- ------ --- ------- ------
------- ------ --- ------- ------
</TABLE>
35
<PAGE>
Options to purchase an additional 320,000 shares of common stock at a
weighted average price of $15.70 per share were granted in February 1998.
The Company granted 32,000, 25,000, and 23,000 shares of restricted stock
during 1995, 1996 and 1997, respectively. Related compensation expense was
recognized in the amounts of approximately $205,000, $98,000, and $120,000 for
the years ended December 31, 1995, 1996, and 1997, respectively. Cumulatively
through December 31, 1997, 53,500 shares of restricted stock had been forfeited,
50,000 shares were no longer subject to restriction, and 40,500 shares of
restricted stock remained subject to forfeiture. An additional 40,000 shares of
restricted stock were granted in February 1998.
The Company granted 55,000 performance shares during 1997. 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 for the year ended December 31, 1997. An additional
50,000 performance shares were granted in February 1998.
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, 48,523 warrants were exercised. The remaining 251,477
warrants were outstanding at December 31, 1997.
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:
<TABLE>
<CAPTION>
Year Ended December 31,
1995 1996 1997
--------- --------- ---------
<S> <C> <C> <C>
Assumptions:
Risk Free Interest Rate 6.75% 6.75% 5.75%
Expected Dividend Yield 0% 0% 0%
Expected Life in Years 5 5 5
Expected Volatility 55% 55% 58%
Weighted Average
Fair Value Per Share $ 2.96 $ 2.73 $ 5.66
Pro Forma Net Income
(Loss)(in thousands) $(19,578) $15,468 $2,285
Pro Forma Diluted Earnings
(Loss) Per Share $ (1.83) $ 1.44 $ .20
</TABLE>
36
<PAGE>
(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:
<TABLE>
<CAPTION>
Future minimum Future minimum
lease obligations lease receipts
----------------- --------------
(in thousands)
<S> <C> <C>
1998 $1,070 $502
1999 1,031 478
2000 132 --
------ ----
$2,233 $980
------ ----
------ ----
</TABLE>
Payments related to these lease obligations were approximately $710,000,
$707,000, and $990,000 for the years ended December 31, 1995, 1996 and 1997,
respectively. Related receipts were $18,000, $89,000 and $502,000 for the years
ended December 31, 1995, 1996 and 1997.
LEGAL PROCEEDINGS - The Company, from time to time, is involved in various
legal and administrative proceedings and claims of various types which arise in
the ordinary course of its business. While any litigation contains an element of
uncertainty, in the opinion of management, none of these actions, either
individually or in the aggregate will have a material adverse effect on 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:
<TABLE>
<CAPTION>
Year Ended December 31,
(in thousands) 1995 1996 1997
------- ------ --------
<S> <C> <C> <C>
Current Provision (Benefit):
Federal $ -- $ 950 $ (434)
State -- 50 (37)
------- ------ --------
-- 1,000 (471)
------- ------ --------
Deferred Provision (Benefit):
Federal (6,970) 4,760 1,795
State (814) -- --
------- ------ --------
(7,784) 4,760 1,795
------- ------ --------
Provision (Benefit)
For Income Taxes $(7,784) $5,760 $ 1,324
------- ------ --------
------- ------ --------
</TABLE>
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:
<TABLE>
<CAPTION>
Year Ended December 31,
(in thousands) 1995 1996 1997
-------- ------- ------
<S> <C> <C> <C>
Income (Loss) Before Income Taxes $(27,327) $21,330 $3,780
Computed Tax at The Applicable
Federal Statutory Rate $ (9,291) $ 7,252 $1,285
State Income Tax,
Net of Federal Tax Benefits (689) 704 39
Deferred Tax
Assets Valuation Allowance 2,196 (2,196) --
-------- ------- ------
Income Tax Provision (Benefit) $ (7,784) $ 5,760 $1,324
-------- ------- ------
-------- ------- ------
</TABLE>
37
<PAGE>
The tax effects of significant temporary differences representing deferred
tax assets and liabilities are as follows:
<TABLE>
<CAPTION>
December 31,
(in thousands) 1996 1997
------- -------
<S> <C> <C>
Deferred Tax Liabilities:
Oil and Gas Properties
and Equipment $ 6,235 $ 7,581
Deferred Tax Assets:
Alternative Minimum Tax
Credit Carryforward (1,475) (1,026)
------- -------
Net Deferred Tax Liability $ 4,760 $ 6,555
------- -------
------- -------
</TABLE>
As of December 31, 1997, the Company has alternative minimum tax credit
carryforwards for income tax purposes of approximately $1,026,000 which may be
utilized to reduce future tax liability of the Company. These carryforwards have
no expiration date.
(7) RELATED PARTY TRANSACTIONS
Prior to the IPO, 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.
<TABLE>
<CAPTION>
Year Ended December 31,
Purchaser 1995 1996 1997
---- ---- ----
<S> <C> <C> <C>
Texaco (a) (a) 46%
PanEnergy 62% 43% (a)
Eighty-Eight Oil Company 16% 26% 21%
(a) less than ten percent
</TABLE>
SECTION 29 TAX CREDITS - The Company received $1,500,000 in 1995, for
transferred Section 29 tax credits associated with its gas production. Such
proceeds were recorded as unearned income and recognized as incremental gas
revenues as the gas was produced and the credits earned. The Company recognized
approximately $2,857,000 of gas sales during the year ended December 31, 1995
related to amortization of such unearned income, including certain payments
received in prior periods.
Costs Incurred - Costs incurred in oil and gas operations and related
depletion per equivalent unit-of- production were as follows:
38
<PAGE>
<TABLE>
<CAPTION>
Year Ended December 31,
(in thousands, except for gas equivalent data) 1995 1996 1997
------- ------ --------
<S> <C> <C> <C>
Property Acquisition-
Unproved $ 2,429 $ 5,056(1) $ 11,057(1)
Proved 3,889 3,067 48,680
Exploration Costs 2,003 10,250 27,995
Development Costs 7,427 4,472 17,901
------- ------ --------
Gross Expenditures $15,748 $22,845 $105,633
------- ------ --------
------- ------ --------
Depletion Per One Thousand
Cubic Feet of Gas Equivalent $ 0.84 $ 0.82 $ 1.12
------- ------ --------
------- ------ --------
</TABLE>
(1) Excludes $4,914,000 and $1,113,000 of costs recouped through the resale of
partial interests in prospects to industry partners in 1996 and 1997,
respectively.
COSTS NOT BEING AMORTIZED - Oil and gas property costs not being amortized
at December 31, 1997, consisted of $15,669,000 of leasehold and seismic costs,
of which $168,000, $2,636,000 and $12,865,000 were incurred in 1995, 1996 and
1997, 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 estimates. Accordingly, reserve estimates are often
different from the quantities of oil and gas that are ultimately recovered.
Further, the estimated future net revenues from proved reserves and the present
value thereof are based upon certain assumptions, including geologic success,
prices, future production levels and costs, that may not prove correct over
time. Predictions of future production levels are subject to great uncertainty,
and the meaningfulness of such estimates is highly dependent upon the accuracy
of the assumptions upon which they are based. Oil and gas prices have fluctuated
widely in recent years. The calculated weighted average sales prices utilized
for the purposes of estimating the Company's proved reserves and future net
revenue were: $18.64 per barrel of oil and $1.56 per Mcf of gas at December 31,
1995; $25.35 per barrel of oil and $3.02 per Mcf of gas at December 31, 1996;
and $16.34 per barrel of oil and $2.32 per Mcf of gas at December 31, 1997.
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.
The following tables are based upon estimates of onshore reserves prepared
by the Company's engineers and audited by Netherland, Sewell & Associates, Inc.,
and upon estimates of offshore reserves prepared by Ryder Scott Company
Petroleum Engineers or by the Company's engineers and audited by Ryder Scott
Company Petroleum Engineers. All of the Company's reserves are located in the
United States.
39
<PAGE>
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:
<TABLE>
<CAPTION>
OIL GAS
(MBbls) (MMcf)
------- --------
<S> <C> <C>
Balance, December 31, 1994 15,141 156,330
Revisions (1,656) (21,172)
Extensions, Discoveries and Additions 931 10,936
Production (1,153) (12,833)
Sales of Reserves In-place (751) (4,957)
Purchases of Reserves In-place 94 3,132
------- --------
Balance, December 31, 1995 12,606 131,436
Revisions 52 (451)
Extensions, Discoveries and Additions 49 6,391
Production (564) (4,776)
Sales of Reserves In-place (6,559) (104,140)
Purchases of Reserves In-place 2,286 1,253
------- --------
Balance, December 31, 1996 7,870 29,713
Revisions (1,439) (6,488)
Extensions, Discoveries and Additions 1,458 32,911
Production (524) (5,509)
Sales of Reserves In-place (56) (1,015)
Purchases of Reserves In-place 845 39,922
------- --------
Balance, December 31, 1997 8,154 89,534
------- --------
------- --------
Proved Developed Reserves -
December 31, 1995 8,397 106,410
December 31, 1996 4,046 19,182
December 31, 1997 4,863 82,571
</TABLE>
STANDARDIZED MEASURE
The following table presents the standardized measure of discounted future
net cash flows related to proved oil and gas reserves:
<TABLE>
<CAPTION>
December 31,
(in thousands) 1995 1996 1997
--------- --------- --------
<S> <C>
Future Production Revenues $ 439,415 $ 289,105 $341,310
Future Production Costs (155,087) (108,522) (79,550)
Future Development Costs (45,907) (20,583) (40,829)
Future Income Taxes (25,644) (39,101) (31,723)
--------- --------- --------
Future Net Cash Flows 212,777 120,899 189,208
Discount (95,529) (57,593) (53,726)
--------- --------- --------
Standardized Measure
of Discounted Future
Net Cash Flows(1) $ 117,248 $ 63,306 $135,482
--------- --------- --------
--------- --------- --------
</TABLE>
(1) Total future net cash flows before income taxes discounted at 10% per annum
are $129,068,000, $83,656,000, and $160,230,000 as of December 31, 1995,
1996 and 1997, 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.
40
<PAGE>
A summary of changes in the standardized measure of discounted future net
cash flows is as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
(in thousands) 1995 1996 1997
-------- -------- --------
<S> <C> <C> <C>
Standardized Measure of Discounted Future
Net Cash Flows, Beginning of Year $141,352 $117,248 $ 63,306
Changes in Sales Prices and Production Costs (8,382) 17,693 (34,217)
Changes in Estimated Future
Development Costs 448 (1,819) 6,973
Sales of Minerals-in-place (3,866) (83,530) (1,019)
Purchase of Minerals-in-place 2,696 10,887 65,644
Revisions of Previous Quantity Estimates (18,026) (169) (11,065)
Costs Incurred That Reduced Future
Development Costs 5,422 -- 2,253
Extensions, Discoveries and Improved Recovery 7,086 16,286 67,973
Sales of Oil and Gas, Net of Production
Costs and Taxes (27,971) (11,577) (18,541)
Accretion of Discount 16,286 12,907 8,366
Net Change in Future Income Taxes 9,665 (8,530) (4,398)
Changes in Production Rates (Timing) and Other (7,462) (6,090) (9,793)
-------- -------- --------
Standardized Measure of Discounted Future
Net Cash Flows, End of Year $117,248 $ 63,306 $135,482
-------- -------- --------
-------- -------- --------
</TABLE>
UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA
<TABLE>
<CAPTION>
(in thousands, except per share amounts)
First Second Third Fourth Total
------ ------- ------ ------- -------
<S> <C> <C> <C> <C> <C>
1996
Revenue $7,576 $27,680 $3,015 $ 3,392 $41,663
Gross profit from operations 5,084 3,295 1,484 1,714 11,577
Net income (loss) (916) 16,375 2 109 15,570
Earnings (loss) per share:
Basic (.09) 1.53 -- .01 1.45
Diluted (.09) 1.52 -- .01 1.45
1997
Revenue $3,412 $ 2,566 $6,906 $11,836 $24,720
Gross profit from operations 1,814 1,269 5,589 9,869 18,541
Net income (loss) 9 (570) 966 2,051 2,456
Earnings (loss) per share:
Basic -- (.05) .09 .16 .22
Diluted -- (.05) .09 .16 .22
</TABLE>
GROSS PROFIT FROM OPERATIONS IS COMPRISED OF OIL AND GAS SALES LESS LEASE
OPERATING EXPENSES AND PRODUCTION TAXES. EARNINGS (LOSS) PER SHARE IS COMPUTED
INDEPENDENTLY FOR EACH OF THE QUARTERS PRESENTED AND THEREFORE MAY NOT SUM TO
THE TOTALS FOR THE YEAR.
41
<PAGE>
(a)(3) Exhibits
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBITS
------- -----------------------
<C> <S>
2.1 -- Agreement and Plan of Merger between Sterling Energy Corporation,
Basin Energy, Inc. and Basin Exploration, Inc. dated October 13,
1994(5)
2.2 -- Plan of Merger between Basin Sterling, Inc. and Basin
Exploration, Inc. dated November 22, 1994(5)
2.3 -- Plan of Merger between Basin Operating Company and Basin
Exploration, Inc. dated December 14, 1994(8)
3.1 -- Restated Certificate of Incorporation of Basin.(2)
3.2 -- Restated Bylaws of Basin.(2)
4.1 -- Common Stock Certificate of Basin.(2)
10.1 -- Equity Incentive Plan as amended April 28, 1997.(13)
10.3 -- Key Employee Participation Plan.(2)
10.4 -- Employment Agreement dated March 31, 1992 by and between Basin
and Michael S. Smith.(3)
10.5 -- Gulf Coast Geoscientist Overriding Royalty Interest Plan dated
November 30, 1995.(10)
10.6 -- Form of Rights Agreement dated as of February 24, 1996, between
Basin Exploration, Inc. and Corporate Stock Transfer, Inc. as
Rights Agent.(9)
10.7 -- Performance Shares Plan approved February 4, 1997.(12)
10.8 -- Change of Control Employment Agreement dated October 13, 1995
between Basin Exploration, Inc. and Howard L. Boigon.(10)
10.9 -- Employment Agreement dated August 28, 1995 between Basin
Exploration, Inc. and Samuel D. Winegrad.(10)
10.10 -- Employment Agreement dated June 28, 1995 between Basin
Exploration, Inc. and Neil L. Stenbuck.(10)
10.11 -- Employment Agreement dated November 10, 1995 between Basin
Exploration, Inc. and David A. Pustka.(10)
10.12 -- Employment Agreement dated February 23, 1996 between Basin
Exploration, Inc. and Thomas J. Corley.(12)
10.13 -- Assignment and Assumption of Lease dated December 18, 1995 by and
between Team, Inc., as original Tenant, Basin Exploration, Inc.,
as New Tenant, and FC Tower Property Partners, L.P., as
Landlord.(9)
10.16 -- Agreement for Purchase and Sale of Assets (Monetization) dated
February 24, 1996 by and between Basin Exploration, Inc., HS
Resources, Inc. and Orion Acquisition, Inc.(7)
10.17 -- Agreement for Purchase and Sale of Assets (Wattenberg), dated
February 24, 1996 by and between Basin Exploration, Inc., HS
Resources, Inc. and Orion Acquisition, Inc.(7)
10.18 -- Lease of Office Space dated September 25, 1992, between
Brookfield Republic Inc. and Basin Operating Company, as
amended(4+)
10.19 -- First Lease of Additional Office Space dated as of December 1,
1994, between Brookfield Republic, Inc. and Basin Operating
Company.(6+)
10.20 -- Amended and Restated Credit Agreement dated August 6, 1996
between the Company and Colorado National Bank, Union Bank of
California, N.A. and NationsBank of Texas, N.A.(11)
10.21 -- Purchase and Sale Agreement dated February 13, 1997, between
Hall-Houston Oil Company et al as Sellers and Basin Exploration,
Inc. as Buyer.(12+)
10.22 -- First Amendment of Amended and Restated Credit Agreement dated
August 6, 1996 between the Company and Colorado National Bank,
Union Bank of California, N.A. and NationsBank of Texas, N.A.
dated June 11, 1997 (14)
10.23 -- Order of the United States Bankruptcy Court for the Southern
District of Texas Corpus Christi Division, dated November 18,
1997, with exhibits, including the Agreement of Purchase and
Sale.(15)
10.24 -- Second Amendment of Amended and Restated Credit Agreement dated
August 6, 1996 between the Company and Colorado National Bank,
Union Bank of California, N.A. and NationsBank of Texas, N.A.
dated November 1, 1997 (1)
</TABLE>
42
<PAGE>
<TABLE>
<C> <S>
21 -- Subsidiaries.(1)
23.1 -- Consent of Arthur Andersen LLP (1)
23.2 -- Consent of Netherland, Sewell & Associates, Inc.(1)
23.3 -- Consent of Ryder Scott Company (1)
27 -- Financial Data Schedule (1)
</TABLE>
- ---------------
(1) Filed herewith.
(2) Filed as an Exhibit to Basin's Registration Statement on Form S-1 as
filed on March 17, 1992, Registration No. 33-46486, and incorporated
herein by reference.
(3) Filed as an Exhibit to Amendment No. 1 to Basin's Registration
Statement on Form S-1 as filed on April 21, 1992, Registration No.
33-46486, and incorporated herein by reference.
(4) Filed as an Exhibit to Basin's Registration Statement on Form S-1 as
filed on October 25, 1993, Registration No. 33-70802, and incorporated
herein by reference.
(5) Filed as an Exhibit to Form 8-K filed on December 10, 1994, and
incorporated herein by reference.
(6) Filed as an Exhibit to Form 10-K/A-1 filed on June 26, 1995 and
incorporated herein by reference.
(7) Filed as an Exhibit to Form 8-K filed on March 6, 1996, and
incorporated herein by reference.
(8) Filed as an Exhibit to Form 10-K filed on March 28, 1995, and
incorporated herein by reference.
(9) Filed as an Exhibit to Form 8-K filed on February 26, 1996, and
incorporated herein by reference.
(10) Filed as an Exhibit to Form 10-K filed on March 28, 1996, and
incorporated herein by reference.
(11) Filed as an Exhibit to Form 10-Q filed on August 14, 1996, and
incorporated herein by reference.
(12) Filed as an Exhibit to Form 10-K filed on March 31, 1997, and
incorporated herein by reference.
(13) Filed as an Exhibit to Form 10-Q filed on May 15, 1997, and
incorporated herein by reference.
(14) Filed as an Exhibit to Form 10-Q filed on August 12, 1997, and
incorporated herein by reference.
(15) Filed as an Exhibit to Form 8-K filed on December 11, 1997, and
incorporated herein by reference.
+ Confidential treatment has been granted for portions of these
Exhibits.
(b) Reports on Form 8-K
The Company filed the following reports on Form 8-K during the last quarter of
the period covered by this report:
Date of Report Filed on Item # Topic
- -------------- -------- ------ -----
October 23, 1997 October 24, 1997 7 Form of Underwriting Agreement
November 7, 1997 November 12, 1997 5 Agreement to acquire certain assets
from Midcon Offshore, Inc.
November 26, 1997 December 11, 1997 2 Consummation of acquisition from
Midcon Offshore, Inc.
43
<PAGE>
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 26, 1998 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 26, 1998
- ------------------------ Officer and Chairman of the
Michael S. Smith Board (Principal Executive Officer)
/s/ HOWARD L. BOIGON Vice President - General Counsel, March 26, 1998
- ------------------------ Secretary and Director
Howard L. Boigon
/s/ NEIL L. STENBUCK Vice President, Chief Financial March 26, 1998
- ------------------------ Officer and Director
Neil L. Stenbuck
/s/ JAMES A. TUELL Controller, Principal Accounting March 26, 1998
- ------------------------ Officer
James A. Tuell
/s/ DONALD H. ANDERSON Director March 26, 1998
- ------------------------
Donald H. Anderson
/s/ JOHN F. GREENE Director March 26, 1998
- ------------------------
John F. Greene
/s/ J. PAUL HELLSTROM Director March 26, 1998
- ------------------------
J. Paul Hellstrom
/s/ MICHAEL A. NICOLAIS Director March 26, 1998
- ------------------------
Michael A. Nicolais
/s/ LARRY D. UNRUH Director March 26, 1998
- ------------------------
Larry D. Unruh
44
<PAGE>
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION OF EXHIBITS
- ------- ----------------------
10.24 -- Second Amendment of Amended and Restated Credit Agreement dated
August 6, 1996 between the Company and Colorado National Bank,
Union Bank of California, N.A. and NationsBank of Texas, N.A.
dated November 1, 1997
21 -- Subsidiaries
23.1 -- Consent of Arthur Andersen LLP
23.2 -- Consent of Netherland Sewell & Associates, Inc.
23.3 -- Consent of Ryder Scott Company
27 -- Financial Data Schedule
<PAGE>
Exhibit 10.24
SECOND AMENDMENT OF
AMENDED AND RESTATED CREDIT AGREEMENT
THIS SECOND AMENDMENT OF AMENDED AND RESTATED CREDIT AGREEMENT (this
"Amendment"), dated as of November 1, 1997, is by and among BASIN EXPLORATION,
INC., a Delaware corporation ("Borrower"), COLORADO NATIONAL BANK ("CNB"), UNION
BANK OF CALIFORNIA, N.A. ("Union"), and NATIONSBANK OF TEXAS, N.A. ("NBT"), in
its capacity as a Lender and as Agent for Lenders. CNB, Union and NBT are
herein collectively referred to as "Lenders."
RECITALS
A. Borrower and Lenders entered into an Amended and Restated Credit
Agreement dated as of August 6, 1996 (the "Original Credit Agreement"), as
amended by a First Amendment of Amended and Restated Credit Agreement dated as
of June 11, 1997 (the "First Amendment"), in order to set forth the terms upon
which Lenders would make loans to Borrower and issue letters of credit at the
request of Borrower and by which such loans and letters of credit would be
governed. Capitalized terms used herein without definition shall have the same
meanings as set forth in the Original Credit Agreement, as amended by the First
Amendment (the "Credit Agreement").
B. The parties hereto wish to enter into this Amendment in order to
amend certain terms and provisions of the Credit Agreement.
AGREEMENT
NOW, THEREFORE, in consideration of $10.00 and other good and valuable
consideration, the receipt and sufficiency of which are hereby acknowledged, the
parties hereby agree as
follows:
1. CREDIT AGREEMENT. Effective as of the date of this
Amendment, the Credit Agreement shall be, and hereby is; amended
as follows:
(a) The definitions of "Regular Borrowing Base" and
"Supplemental Borrowing Base" inserted into Section 1.1 of the Credit Agreement
pursuant to the First Amendment shall be deleted from the Credit Agreement.
(b) The definition of "Base Rate Spread" in Section 1.1 on page
1 of the Credit Agreement shall be deleted, and the following shall be
substituted therefor:
<PAGE>
"BASE RATE SPREAD" means: (a) for any and all calendar
months that the Capitalization Ratio is greater than or equal to 50
percent, 0.25 percentage points per annum; and (b) for any and all calendar
months that the Capitalization Ratio is less than 50 percent, 0.00
percentage points per annum.
(c) The definition of "Borrowing Base" in Section
1.1 on page 3 of the Credit Agreement shall be deleted, and the
following shall be substituted therefor:
"BORROWING BASE" means, at any time, the aggregate loan
value of the Borrowing Base Properties, as determined by Lenders in
accordance with the provisions of Section 3.2 below; provided that, for the
time period from November 1, 1997 to the date as of which the May 1, 1998
redetermination of the Borrowing Base becomes effective, the Borrowing Base
shall be $45,000,000, unless Borrower and Lenders hereafter mutually agree
upon a different amount or unless the Borrowing Base is redetermined
pursuant to Section 3.2 below prior to such redetermination date.
(d) The definition of "Fixed Rate Spread" in
Section 1.1 on page 7 of the Credit Agreement shall be deleted, and the
following shall be substituted therefor:
"FIXED RATE SPREAD" means: (a) for any and all calendar
months that the Capitalization Ratio is greater than or equal to 50
percent, 1.25 percentage points per annum; (b) for any and all calendar
months that the Capitalization Ratio is less than 50 percent but greater
than or equal to 40 percent, 1.00 percentage point per annum; (c) for any
and all calendar months that the Capitalization Ratio is less than 40
percent but greater than or equal to 30 percent, 0.75 percentage point per
annum; and (d) for any and all calendar months that the Capitalization
Ratio is less than 30 percent, 0.625 percentage point per annum.
(e) Section 3.6(a) on pages 22 and 23 of the Credit Agreement shall
be deleted, and the following shall be substituted therefor:
Section 3.6. FEES. (a) Borrower shall pay to Agent, on
behalf of Lenders (and Agent shall pay each Lender its respective
Proportionate Share
<PAGE>
thereof on the Business Day that any such payment is deemed to be received
from Borrower), within 30 days after the end of each three-month period
ending on the last day of January, April, July or October during the
Revolving Period, commencing with the three-month period ending January 31,
1998, a commitment fee, computed on a daily basis for such three-month
period, in an amount equal to: (i) the Commitment Fee Rate, times (ii) the
excess of the Commitment Amount over the sum of the outstanding principal
balance of the Loan plus the face amount of all Letters of Credit
outstanding hereunder.
2. LOAN DOCUMENTS. All references in any document to the Credit
Agreement shall refer to the Credit Agreement, as amended and supplemented
pursuant to this Amendment.
3. CONDITIONS PRECEDENT. The obligations of the parties under this
Amendment are subject, at the option of Lenders, to the prior satisfaction of
the condition that Borrower shall have executed and/or delivered, or caused to
have been executed and/or delivered, to or for the benefit of Lenders, the
following (all documents to be satisfactory in form and substance to Lenders):
(a) This Amendment.
(b) Such certificates of officers of Borrower as may be required
by Lenders.
(c) Any and all other Loan Documents required by Lenders.
4. REPRESENTATIONS AND WARRANTIES. Borrower hereby certifies to
Lenders that as of the date of (and after giving effect to) this Amendment,
except as heretofore disclosed to and waived by Lenders: (a) all of Borrower's
representations and warranties contained in the Credit Agreement are true,
accurate and complete in all material respects, and (b) no Default or Event of
Default has occurred and is continuing under the Credit Agreement.
5. CONTINUATION OF THE CREDIT AGREEMENT. Except as specified in
this Amendment, the provisions of the.,Credit Agreement shall remain in full
force and effect, and if there is a conflict between the terms of this Amendment
and those of the Credit Agreement, the terms of this Amendment shall control.
Borrower hereby ratifies, confirms and adopts the Credit Agreement, as amended
hereby.
<PAGE>
6. EXPENSES. Borrower shall pay all reasonable expenses incurred in
connection with the transactions contemplated by this Amendment, including
without limitation all reasonable fees and reasonable expenses of Lenders'
attorneys and all recording and filing fees, charges and expenses.
7. MISCELLANEOUS. This Amendment shall be governed by and construed
under the laws of the State of Colorado and shall be binding upon and inure to
the benefit of the parties hereto and their successors and assigns. This
Amendment may be executed in any number of counterparts, each of which shall be
an original, but all of which together shall constitute one instrument. Delivery
of this Amendment and any and all documents to be delivered in connection
herewith by any party may be effected, without limitation, by faxing a signed
counterpart of this Amendment to NBT (any party that effects delivery in such
manner hereby agreeing to transmit promptly to NBT an actual signed
counterpart).
EXECUTED as of the date first above written.
BASIN EXPLORATION, INC.
By: /s/ Neil L. Stenbuck
-----------------------------------------
Vice President/Chief Financial
Officer
COLORADO NATIONAL BANK
By: /s/ Kathryn A. Gaiter
-----------------------------------------
Vice President
NATIONSBANK OF TEXAS, N.A., in its
capacity as a Lender and as Agent
for Lenders
By: /s/ David C. Rubenking
-----------------------------------------
Senior Vice President
UNION BANK OF CALIFORNIA, N.A.
By: /s/ Randall L. Osterberg
-----------------------------------------
Vice President
By: /s/ Tony R. Weber
-----------------------------------------
Vice President
<PAGE>
Exhibit 21
SUBSIDIARIES OF BASIN EXPLORATION, INC. AT 12/31/97
Basin Drilling, Inc.
Basin Offshore Oil & Gas, Inc.
<PAGE>
Exhibit 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our report included in this Form 10-K, into Basin Exploration, Inc.'s
previously filed registration statements File Nos. 33-63528 and 333-36143.
/s/ ARTHUR ANDERSEN LLP
Denver, Colorado
March 27, 1998.
<PAGE>
Exhibit 23.2
March 27, 1998
Basin Exploration, Inc.
Suite 3400
370 Seventeenth Street
Denver, Colorado 80202
Ladies and Gentlemen:
We hereby authorize the reference to the following report prepared by
Netherland, Sewell & Associates, Inc. in a Registration Statement on Form S-3
and Form S-8 for the offering and sale of Securities, as described in such
Registration Statement, and in any prospectus contained therein or prospectus
supplement thereto, filed or to be filed by Basin Exploration, Inc. with the
United States Securities and Exchange Commission:
1. An audit of onshore proved oil and gas reserves and future revenue
prepared by Basin Exploration, Inc., as of January 1, 1998, dated
January 21, 1998.
We further consent to the reference to our firm under the caption "Experts"
in such Registration Statement and prospectuses, as such Registration Statement
may be amended.
Very truly yours,
NETHERLAND, SEWELL & ASSOCIATES, INC.
/s/ Clarence M. Netherland, Chairman
<PAGE>
Exhibit 23.3
Basin Exploration, Inc.
370 Seventeenth Street, Suite 3400
Denver, Colorado 80202
Ladies and Gentlemen:
We hereby authorize the reference to the following report prepared by Ryder
Scott Company in a Registration Statement on Forms S-3 and S-8 and in any
prospectus contained therein of filed by Basin Exploraton, Inc. with the United
States Securities and Exchange Commission:
1. Estimated Future Reserves and Income Attributable to Certain Leasehold
and Royalty Interests (SEC Parameters) as of January 1, 1998.
We further consent to the reference to our firm under the caption "Experts"
in such Registration Statement and prospectuses, as such Registration Statement
may be amended.
/s/ RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
Houston, Texas
March 26, 1998
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
COMPANY'S AUDITED CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED DECEMBER
31, 1997, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> DEC-31-1997
<CASH> 531
<SECURITIES> 0
<RECEIVABLES> 8,348
<ALLOWANCES> 0
<INVENTORY> 215
<CURRENT-ASSETS> 12,684
<PP&E> 199,445
<DEPRECIATION> 50,270
<TOTAL-ASSETS> 161,959
<CURRENT-LIABILITIES> 22,720
<BONDS> 11,053
0
0
<COMMON> 138
<OTHER-SE> 121,227
<TOTAL-LIABILITY-AND-EQUITY> 161,959
<SALES> 24,401
<TOTAL-REVENUES> 24,720
<CGS> 5,860
<TOTAL-COSTS> 20,176
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 764
<INCOME-PRETAX> 3,780
<INCOME-TAX> 1,324
<INCOME-CONTINUING> 2,456
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 2,456
<EPS-PRIMARY> .22
<EPS-DILUTED> .22
</TABLE>
