<PAGE>
INFORMATION CONTAINED HEREIN IS SUBJECT TO COMPLETION OR AMENDMENT. A
REGISTRATION STATEMENT RELATING TO THESE SECURITIES HAS BEEN FILED WITH THE
SECURITIES AND EXCHANGE COMMISSION. THIS PROSPECTUS SUPPLEMENT SHALL NOT
CONSTITUTE AN OFFER TO SELL OR THE SOLICITATION OF AN OFFER TO BUY, NOR SHALL
THERE BE ANY SALE OF THESE SECURITIES IN ANY STATE IN WHICH SUCH OFFER,
SOLICITATION OR SALE WOULD BE UNLAWFUL PRIOR TO REGISTRATION OR QUALIFICATION
UNDER THE SECURITIES LAWS OF ANY SUCH STATE.
<PAGE>
FILED PURSUANT TO RULE 424B(2)
FILE NO. 333-36143
PRELIMINARY PROSPECTUS SUPPLEMENT
(TO PROSPECTUS DATED OCTOBER 2, 1997)
2,700,000 SHARES
[LOGO]
BASIN EXPLORATION, INC.
COMMON STOCK
------------------------
Of the 2,700,000 shares of Common Stock of Basin Exploration, Inc. offered
hereby (the "Offering"), 2,500,000 shares are being sold by the Company and
200,000 shares are being sold by the Selling Stockholder. See "Selling
Stockholder." The Company will not receive any of the proceeds from the sale of
shares by the Selling Stockholder.
The Common Stock is traded on the Nasdaq National Market under the trading
symbol "BSNX." The last reported sale price of the Common Stock on the Nasdaq
National Market on October 8, 1997, was $18 9/16 per share.
SEE "RISK FACTORS" BEGINNING ON PAGE S-11 FOR A DISCUSSION OF CERTAIN
FACTORS THAT SHOULD BE CONSIDERED IN CONNECTION WITH AN INVESTMENT IN THE COMMON
STOCK OFFERED HEREBY.
------------------------
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE
ACCURACY OR ADEQUACY OF THIS PROSPECTUS SUPPLEMENT OR THE ACCOMPANYING
PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
<TABLE>
<CAPTION>
UNDERWRITING PROCEEDS TO PROCEEDS TO
PRICE TO PUBLIC DISCOUNT(1) COMPANY(2) SELLING STOCKHOLDER
<S> <C> <C> <C> <C>
Per Share........................ $ $ $ $
Total(3)......................... $ $ $ $
</TABLE>
(1) The Company and the Selling Stockholder have agreed to indemnify the
Underwriters against certain liabilities, including liabilities under the
Securities Act of 1933, as amended (the "Securities Act"). See
"Underwriting."
(2) Before deducting expenses of the Offering, estimated to be approximately
$400,000, payable by the Company.
(3) The Company and the Selling Stockholder have granted the Underwriters
options to purchase up to an additional 375,000 and 30,000 shares of Common
Stock, respectively, on the same terms as set forth above, solely to cover
over-allotments, if any. If such options are exercised in full, the total
Price to Public, Underwriting Discount, Proceeds to Company and Proceeds to
Selling Stockholder will be $ , $ , $ and
$ , respectively. See "Underwriting."
------------------------
The shares of Common Stock offered by this Prospectus Supplement are being
offered by the Underwriters, subject to prior sale, when, as and if issued to
and accepted by the Underwriters, and subject to certain other conditions. The
Underwriters reserve the right to withdraw, cancel or modify such offer and to
reject orders in whole or in part. It is expected that delivery of the shares of
Common Stock will be made on or about October , 1997 at the offices of Morgan
Keegan & Company, Inc., Memphis, Tennessee.
------------------------
MORGAN KEEGAN & COMPANY, INC.
HOWARD, WEIL, LABOUISSE, FRIEDRICHS
INCORPORATED
PETRIE PARKMAN & CO.
RAUSCHER PIERCE REFSNES, INC.
THE DATE OF THIS PROSPECTUS SUPPLEMENT IS OCTOBER , 1997
<PAGE>
[map]
CERTAIN PERSONS PARTICIPATING IN THE OFFERING MAY ENGAGE IN TRANSACTIONS
THAT STABILIZE, MAINTAIN OR OTHERWISE AFFECT THE PRICE OF THE COMMON STOCK,
INCLUDING OVER-ALLOTMENTS, ENTERING STABILIZING BIDS, EFFECTING SYNDICATE
COVERING TRANSACTIONS AND IMPOSING PENALTY BIDS. FOR A DESCRIPTION OF THESE
ACTIVITIES, SEE "UNDERWRITING."
IN CONNECTION WITH THE OFFERING, THE UNDERWRITERS MAY ENGAGE IN PASSIVE
MARKET MAKING TRANSACTIONS IN THE COMMON STOCK ON THE NASDAQ NATIONAL MARKET IN
ACCORDANCE WITH RULE 103 OF REGULATION M UNDER THE SECURITIES EXCHANGE ACT OF
1934, AS AMENDED (THE "EXCHANGE ACT"). SEE "UNDERWRITING."
<PAGE>
PROSPECTUS SUPPLEMENT SUMMARY
THE FOLLOWING SUMMARY IS QUALIFIED IN ITS ENTIRETY BY THE DETAILED
INFORMATION AND FINANCIAL STATEMENTS FOUND ELSEWHERE IN THIS PROSPECTUS
SUPPLEMENT. UNLESS OTHERWISE INDICATED, ALL INFORMATION IN THIS PROSPECTUS
SUPPLEMENT ASSUMES NO EXERCISE OF THE UNDERWRITERS' OVER-ALLOTMENT OPTIONS. SEE
"UNDERWRITING." AS USED IN THIS PROSPECTUS SUPPLEMENT, THE TERMS "BASIN" AND THE
"COMPANY" REFER TO BASIN EXPLORATION, INC. AND ITS SUBSIDIARY, UNLESS OTHERWISE
STATED OR INDICATED BY THE CONTEXT. CERTAIN TERMS USED HEREIN RELATING TO THE
OIL AND GAS INDUSTRY AND CERTAIN OTHER CAPITALIZED TERMS ARE DEFINED IN THE
"GLOSSARY" INCLUDED ELSEWHERE IN THIS PROSPECTUS SUPPLEMENT.
THE COMPANY
Basin Exploration, Inc. is engaged in the exploration, acquisition,
development and exploitation of oil and gas properties. The Company's oil and
gas 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 September 30, 1997, the Company's estimated net proved reserves were 60.3 Bcf
of natural gas and 8.3 MMBbl of oil, or 110.1 Bcfe, with an aggregate PV-10
Value of $151.1 million.
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 Denver-Julesburg ("D-J") Basin
properties in Colorado for $123.5 million (the "D-J Sales").
Since commencing operations in the Gulf of Mexico at the beginning of 1996,
through September 30, 1997 (giving effect to the D-J Sales as if they had
occurred at December 31, 1995) Basin has:
- Successfully drilled six of 11 exploratory wells in the Gulf of Mexico.
- Assembled 30 Gulf of Mexico exploratory prospects, 21 of which were
internally generated and 20 of which remain to be drilled.
- Completed three acquisitions of properties with proved reserves and
exploration or exploitation potential for an aggregate acquisition cost of
approximately $20 million.
- Built estimated net proved reserves in the Gulf of Mexico from 0 to 48.1
Bcfe at an average Finding Cost of approximately $1.05 per Mcfe.
- Increased total estimated net proved reserves by 76% from 62.6 Bcfe to
110.1 Bcfe.
- Increased the PV-10 Value of estimated net proved reserves by 259% from
$42.1 million to $151.1 million.
- Increased average net daily production from approximately 12.3 MMcfe to
43.6 MMcfe, primarily due to commencement of production in August 1997
from two Gulf of Mexico discovery wells, with further increases expected
from five Gulf of Mexico wells that are currently either being completed
or are temporarily suspended pending additional development.
The Company drilled three Gulf of Mexico exploratory wells in 1996, drilled
eight exploratory wells during the first nine months of 1997 and expects to
drill 12 to 15 additional exploratory wells in the Gulf of Mexico through the
end of 1998, one of which is currently being drilled. The Company currently
estimates that its aggregate capital expenditures for the balance of 1997 and
1998 will be between $60 million and $80 million, excluding acquisitions.
S-3
<PAGE>
BUSINESS STRATEGY
Basin's business strategy is to generate strong per share growth in
reserves, production, earnings and cash flow through a balanced approach to
exploration, development and selective acquisitions of oil and gas properties.
The Company implements this strategy through the following:
FOCUS ON EXPLORATION IN THE SHALLOW WATERS OF THE GULF OF MEXICO. Basin's
exploration activities are focused in the shallow waters of the central Gulf of
Mexico, primarily offshore Louisiana. The Company believes that this region has
significant remaining undiscovered reserves and that the combination of existing
infrastructure and effectiveness of 3-D seismic will reduce exploration risk and
enhance project economics.
CAPITALIZE ON TECHNICAL EXPERTISE. Basin has assembled a team of
geoscientists and petroleum engineers with substantial expertise in the shallow
waters of the Gulf of Mexico to generate prospects and evaluate acquisition
opportunities. Basin has also added senior management with substantial
acquisition experience outside the Gulf of Mexico and intends to utilize this
in-house capability in conjunction with regionally specialized geoscientists to
identify and evaluate growth opportunities through acquisitions with additional
exploration and exploitation potential.
UTILIZE ADVANCED TECHNOLOGY. Basin makes extensive use of advanced
technologies, including 3-D seismic and computer-aided exploration 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 200 lease blocks of 3-D seismic data in the Gulf
of Mexico.
BALANCE SIZE AND RISK PROFILE OF EXPLORATION TARGETS. Basin conducts 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 to reduce development costs
and expedite the commencement of production. This balance allows the Company to
mitigate risk while gaining exposure to meaningful growth in reserves and
production.
GENERATE PROSPECTS INTERNALLY. Basin's team of geoscientists internally
generates high quality 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 to swap for interests in third-party
generated prospects.
OPERATE CORE PROPERTIES. At September 30, 1997, Basin served as operator
for properties accounting for more than 80% of the Company's PV-10 Value.
Serving as operator allows the Company to exert greater control over the cost
and timing of its exploration, development and production activities.
PURSUE SELECTIVE ACQUISITIONS. Basin actively seeks to acquire working
interests in oil and gas properties with development potential to augment
operations in its core areas, to build acreage positions for exploration
prospects and to establish positions in new areas.
MAINTAIN FINANCIAL FLEXIBILITY. Basin is committed to maintaining financial
flexibility in order to pursue exploration and development activities and take
advantage of selective acquisition opportunities. The Offering will enhance
Basin's financial flexibility by further strengthening its balance sheet.
RISK FACTORS
See "Risk Factors" for a discussion of certain factors that should be
considered in connection with an investment in the Common Stock offered hereby.
S-4
<PAGE>
THE OFFERING
<TABLE>
<S> <C>
Common Stock Offered:
By the Company.................. 2,500,000
By the Selling Stockholder...... 200,000
Common Stock Outstanding After the
Offering........................ 13,256,774(1)
Use of Proceeds................... The net proceeds to the Company will be used to repay
indebtedness, to fund exploration and development
activities, for possible future acquisitions of oil and
gas properties and for general corporate purposes. The
Company will not receive any proceeds from the sale of
Common Stock by the Selling Stockholder. See "Use of
Proceeds."
Nasdaq National Market Symbol..... BSNX
</TABLE>
- ------------------------
(1) Excludes 784,000 shares of Common Stock reserved for issuance upon the
exercise of outstanding stock options and 300,000 shares of Common Stock
issuable on exercise of outstanding warrants. See "Capitalization."
S-5
<PAGE>
SUMMARY RESERVE DATA
The following table sets forth summary information with respect to Basin's
estimated net proved oil and gas reserves and the PV-10 Value of the Company's
estimated net proved reserves as of September 30, 1997 and December 31, 1996.
Basin's offshore oil and gas reserves are based upon reserve reports prepared by
Ryder Scott Company, independent petroleum engineers ("Ryder Scott"), and
Basin's onshore reserves are based upon reserve reports prepared by the Company
and audited by Netherland, Sewell & Associates, Inc., independent petroleum
engineers ("Netherland Sewell"). For limitations on the accuracy and reliability
of estimated net proved reserves and future net revenue, see "Risk Factors--
Estimates of Reserves and Related Data."
<TABLE>
<CAPTION>
AS OF AS OF
SEPTEMBER 30, 1997 DECEMBER 31, 1996
------------------ -----------------
<S> <C> <C>
Total net proved:
Oil (MBbls).......................................... 8,310 7,870
Gas (MMcf)........................................... 60,268 29,713
Total (MMcfe)........................................ 110,128 76,933
Net proved developed:
Oil (MBbls).......................................... 4,399 4,046
Gas (MMcf)........................................... 40,343 19,182
Total (MMcfe)........................................ 66,737 43,458
PV-10 Value (in thousands)(1).......................... $ 151,074 $ 83,656
</TABLE>
- ------------------------
(1) Future cash flows attributable to Basin's estimated net proved reserves were
based on an average gas price of $2.80 per Mcf and an average oil price of
$20.08 per Bbl at September 30, 1997 and an average gas price of $3.02 per
Mcf and an average oil price of $25.35 per Bbl at December 31, 1996.
S-6
<PAGE>
SUMMARY OPERATING DATA
The following table sets forth summary data with respect to the production
and sales prices of oil and gas by the Company for the periods indicated.
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30, YEAR ENDED DECEMBER 31,
-------------------- ---------------------- -------------------------------
1997(1) 1996 1997(1)(2) 1996 1996(2) 1995 1994
--------- --------- ----------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
Net production:
Oil (MBbls)....................... 147 98 356 466 564 1,153 1,278
Gas (MMcf)........................ 1,688 429 2,490 4,353 4,776 12,833 14,377
Total (MMcfe)..................... 2,570 1,017 4,626 7,149 8,160 19,751 22,045
Average net daily production:
Oil (Bbls)........................ 1,600 1,064 1,304 1,699 1,540 3,160 3,501
Gas (Mcf)......................... 18,353 4,664 9,121 15,886 13,050 35,154 39,389
Total (Mcfe)...................... 27,953 11,048 16,945 26,080 22,290 54,114 60,395
Average sales price per unit(3):
Oil (per Bbl)..................... $ 18.59 $ 21.10 $ 18.88 $ 19.55 $ 20.03 $ 17.02 $ 15.63
Gas (per Mcf)..................... $ 2.45 $ 1.22 $ 2.37 $ 1.39 $ 1.44 $ 1.56 $ 1.69
Total (per Mcfe).................. $ 2.67 $ 2.54 $ 2.73 $ 2.12 $ 2.23 $ 2.01 $ 2.01
Production cost per Mcfe(4)......... $ 0.50 $ 1.08 $ 0.86 $ 0.74 $ 0.81 $ 0.59 $ 0.55
</TABLE>
- ------------------------
(1) For the month of September 1997, which included the first full month of
production from the Company's Eugene Island Block 65 property, Basin's net
production totaled 1,307 MMcfe, average net daily production totaled 43,573
Mcfe, average sales price per unit totaled $2.71 per Mcfe and production
cost per Mcfe totaled $0.31.
(2) Production decreased from 1995 to 1996 and from the first nine months of
1996 to the first nine months of 1997 as a result of the D-J Sales
consummated in the first half of 1996. As of December 31, 1995, the assets
sold in the D-J Sales represented approximately two-thirds of the Company's
producing wells and 70% of its estimated net proved reserves. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Results of Operations."
(3) Includes the effects of the Company's hedging activities. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
(4) Includes direct lifting costs (labor, repairs and maintenance, materials and
supplies) and the administrative costs of production offices, insurance and
property and severance taxes.
S-7
<PAGE>
SUMMARY CONSOLIDATED FINANCIAL DATA
The following table sets forth certain consolidated financial data for the
Company as of and for each of the periods indicated. The financial data for each
year in the three years ended December 31, 1996, are derived from the audited
financial statements of the Company. The financial data for the three and nine
months ended September 30, 1997 and 1996 are derived from the Company's
unaudited financial statements which, in the opinion of management of the
Company, have been prepared on the same basis as the annual consolidated
financial statements and include all adjustments (consisting of only normal
recurring adjustments) necessary for a fair presentation of the financial data
for such periods.
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30, YEAR ENDED DECEMBER 31,
---------------------- ---------------------- ----------------------------------
1997(1) 1996 1997(1)(2) 1996 1996(2) 1995 1994
---------- ---------- ---------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenue:
Oil and gas sales................. $ 6,876 $ 2,586 $ 12,630 $ 15,168 $ 18,182 $ 39,645 $ 44,226
Gain on sale of assets............ -- -- -- 22,472 22,472 -- --
Interest and other................ 30 429 254 631 1,009 831 161
---------- ---------- ---------- ---------- ---------- ---------- ----------
6,906 3,015 12,884 38,271 41,663 40,476 44,387
---------- ---------- ---------- ---------- ---------- ---------- ----------
Costs and expenses:
Lease operating expenses.......... 1,029 819 3,065 3,823 4,776 8,196 8,642
Production taxes.................. 258 283 893 1,482 1,829 3,478 3,432
Depreciation, depletion and
amortization.................... 2,979 1,081 5,375 6,551 7,606 17,202 18,163
General and administrative, net... 838 802 2,441 3,014 3,850 5,498 4,641
Interest and other expense........ 316 27 487 2,245 2,272 6,929 3,618
Property impairment(3)............ -- -- -- -- -- 26,500 --
---------- ---------- ---------- ---------- ---------- ---------- ----------
5,420 3,012 12,261 17,115 20,333 67,803 38,496
---------- ---------- ---------- ---------- ---------- ---------- ----------
Income (loss) before income taxes... 1,486 3 623 21,156 21,330 (27,327) 5,891
Income tax (provision) benefit...... (520) (1) (218) (5,695) (5,760) 7,784 (2,236)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Net income (loss)................... $ 966 $ 2 $ 405 $ 15,461 $ 15,570 $ (19,543) $ 3,655
---------- ---------- ---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ---------- ---------- ----------
Earnings (loss) per share........... $ 0.09 $ -- $ 0.04 $ 1.44 $ 1.45 $ (1.82) $ 0.34
---------- ---------- ---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ---------- ---------- ----------
Weighted average common shares
outstanding........................ 10,757 10,701 10,720 10,700 10,700 10,710 10,813
OTHER FINANCIAL DATA:
Cash flow from operations before
changes in working capital......... $ 4,955 $ 1,101 $ 6,611 $ 3,432 $ 5,680 $ 17,050 $ 24,973
Net cash provided by operating
activities......................... $ 4,792 $ 2,751 $ 3,549 $ 4,488 $ 4,909 $ 10,320 $ 29,261
Capital additions................... $ 13,067 $ 15,587 $ 47,267 $ 20,628 $ 27,741 $ 17,782 $ 62,321
EBITDA(4)........................... $ 4,781 $ 1,111 $ 6,485 $ 7,480 $ 8,736 $ 23,304 $ 27,672
</TABLE>
FOOTNOTES ON NEXT PAGE
S-8
<PAGE>
<TABLE>
<CAPTION>
AS OF SEPTEMBER 30, 1997
--------------------------
ACTUAL AS ADJUSTED(5)
---------- --------------
(IN THOUSANDS)
<S> <C> <C>
BALANCE SHEET DATA:
Working capital (deficit)............................................................. $ (2,159) $ 18,291
Net property and equipment............................................................ 100,970 100,970
Total assets.......................................................................... 113,250 133,700
Long-term debt, net of current portion................................................ 23,092 92
Total stockholders' equity............................................................ 69,334 112,784
</TABLE>
- ------------------------
(1) For the month of September 1997, which included the first full month of
production from the Company's Eugene Island Block 65 property, Basin's
revenue, income before income taxes and cash flow from operations before
changes in working capital were $3,550,000, $1,219,000 and $2,513,000
(exclusive of a change in estimate of current taxes payable for fiscal
1996), respectively.
(2) Oil and gas sales and certain expenses decreased from 1995 to 1996 and from
the first nine months of 1996 to the first nine months of 1997 as a result
of the D-J Sales. As of December 31, 1995, the Company's assets in the D-J
Basin represented approximately two-thirds of the Company's producing wells
and 70% of its proved oil and gas reserves. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Results of
Operations."
(3) During 1995, Basin recognized a property impairment 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. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Results of Operations" and the Company's consolidated financial
statements.
(4) EBITDA is defined as income before interest, income taxes, depreciation,
depletion and amortization, property impairment and gain on sale of assets.
EBITDA is a financial measure commonly used in the Company's industry and
should not be considered in isolation or as a substitute for net income, net
cash provided by operating activities or other income or cash flow data
prepared in accordance with generally accepted accounting principles or as a
measure of a company's profitability or liquidity. Because EBITDA excludes
some, but not all, items that affect net income and may vary among
companies, the EBITDA presented above may not be comparable to similarly
titled measures of other companies.
(5) As adjusted for the Offering and the application of the estimated net
proceeds to the Company therefrom. See "Capitalization."
S-9
<PAGE>
UNCERTAINTY OF FORWARD-LOOKING INFORMATION
This Prospectus Supplement includes statements that are not purely
historical and are "forward-looking statements" within the meaning of Section
27A of the Securities Act and Section 21E of the Exchange Act. Forward-looking
statements involve risks and uncertainties that could cause actual results to
differ from projected results. Such statements address activities, events or
developments that the Company expects, believes, projects, intends or
anticipates will or may occur, including such matters as future capital,
development and exploration expenditures (including the amount and nature
thereof), drilling of exploration and development wells, future production of
oil and gas, expansion into additional areas, cash flow, borrowing capacity and
anticipated liquidity, prospect development and property acquisition, or
marketing of oil and gas. Factors that could cause actual results to differ
materially ("Cautionary Disclosures") include, among others: general economic
conditions, the market price of oil and natural gas, the risks associated with
exploration, the Company's ability to find, acquire, market, develop and produce
new properties, operating hazards attendant to the oil and natural gas business,
downhole drilling and completion risks that are generally not recoverable from
third parties or insurance, concentration of the Company's production in a small
number of properties in the Gulf of Mexico, uncertainties in the estimation of
proved reserves and in the projection of future rates of production and timing
of development expenditures, potential mechanical failure 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 other
factors described in this Prospectus Supplement, the Prospectus and in the
Company's reports filed with the Securities and Exchange Commission ("SEC").
Many of such factors are beyond the Company's ability to control or predict. All
forward-looking statements included or incorporated by reference in this
Prospectus Supplement are based on information available to the Company on the
date hereof. Although the Company believes that the assumptions and expectations
reflected in such forward-looking statements are reasonable, it can give no
assurance that such expectations will prove to have been correct or that the
Company will take any actions that may presently be planned. Prospective
investors are cautioned not to put undue reliance on forward-looking statements.
Certain important factors that could cause actual results to differ materially
from the Company's expectations are disclosed under "Risk Factors" and elsewhere
in this Prospectus Supplement and the Prospectus delivered herewith. 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.
S-10
<PAGE>
RISK FACTORS
PROSPECTIVE PURCHASERS OF COMMON STOCK SHOULD CAREFULLY READ THIS PROSPECTUS
SUPPLEMENT, THE PROSPECTUS DELIVERED HEREWITH, AND THE DOCUMENTS INCORPORATED BY
REFERENCE HEREIN AND THEREIN. OWNERSHIP OF COMMON STOCK INVOLVES CERTAIN RISKS.
IN DETERMINING WHETHER TO PURCHASE THE COMMON STOCK, PROSPECTIVE INVESTORS
SHOULD CONSIDER CAREFULLY THE FOLLOWING RISK FACTORS, THE RISK FACTORS
IDENTIFIED IN THE ACCOMPANYING PROSPECTUS AND THE OTHER INFORMATION CONTAINED IN
THIS PROSPECTUS SUPPLEMENT AND THE PROSPECTUS DELIVERED HEREWITH.
OIL AND GAS PRICES; HEDGING
Basin's revenues, profitability and future growth, and the carrying value of
its oil and gas properties, are substantially dependent upon prevailing prices
for oil, gas and natural gas liquids. For much of the past decade, the prices
for oil and natural gas have been extremely volatile. The Company anticipates
that such prices will continue to be volatile in the foreseeable future. In
general, future prices of oil, gas and natural gas liquids are dependent upon
numerous external factors such as weather, various economic, political and
regulatory developments and competition from other sources of energy. The
unsettled nature of the energy market and the unpredictability of worldwide
political developments, including, for example, actions of OPEC members, make it
particularly difficult to estimate future prices of oil, gas and natural gas
liquids. Any significant decline in the price of oil, gas or natural gas liquids
for an extended period would have a material adverse effect on the Company's
financial condition and results of operations, and would, under certain
circumstances, result in a reduction in funds available under the Company's bank
credit facilities, impair access to other sources of capital and curtail the
Company's capital expenditures.
Volatile oil and gas prices make it difficult to estimate the value of
producing properties for acquisition and often cause disruption in the market
for oil and gas producing properties, as buyers and sellers have difficulty
agreeing on such value. Price volatility also makes it difficult to budget for
and project the return on acquisitions and development and exploitation
projects.
From time to time, as conditions are deemed to warrant, the Company enters
into energy price swap arrangements to reduce its exposure to oil and gas price
volatility. Such arrangements are subject to a number of risks. If the Company's
reserves are not produced at the rates estimated by the Company due to
inaccuracies in the reserve estimation process, operational difficulties or
regulatory limitations, the Company would be required to satisfy its obligations
under hedging contracts on potentially unfavorable terms without the ability to
hedge that risk through sales of comparable quantities of its own production.
Further, the terms under which the Company enters into hedging contracts are
based on assumptions and estimates of numerous factors such as cost of
production and pipeline and other transportation costs to delivery points. Under
financial instrument contracts, the Company may also be at risk for basis
differential, which is the difference in the quoted financial price for contract
settlement and the actual price received at the physical point of delivery.
Substantial variations between the assumptions and estimates used by the Company
and actual results experienced could materially adversely affect the Company and
its ability to manage the risk associated with fluctuations in oil and gas
prices. In addition, hedging contracts are subject to the risk that the other
party may prove unable or unwilling to perform its obligations under such
contracts. Any significant nonperformance could have a material adverse
financial effect on the Company. Furthermore, hedging contracts limit the
benefits the Company would realize if actual prices rise above the contract
prices.
EXPLORATION RISKS
With the sale of its D-J Basin properties in 1996, and its initiation of
exploration activities in the Gulf of Mexico, the Company currently is spending
a large portion of its capital budget on exploration. Exploration activities
involve substantially more risk than development or exploitation activities.
Exploratory drilling is a speculative activity. Even when fully utilized and
properly interpreted, 3-D seismic data and visualization techniques only assist
geoscientists in identifying subsurface structures and hydrocarbon
S-11
<PAGE>
indicators and do not conclusively allow the interpreter to know if hydrocarbons
will in fact be present in such structures. In addition, the use of 3-D seismic
data and such technologies requires greater predrilling expenditures than
traditional drilling strategies and the Company could incur losses as a result
of such expenditures. Failure of the Company's exploration activities would have
a material adverse effect on the Company's future results of operations and
financial condition.
CONCENTRATION OF VALUE
The two wells in the Company's Eugene Island Block 65 property contain
approximately 38% of the PV-10 Value attributable to the Company's estimated net
proved reserves as of September 30, 1997 and, based upon Basin's reserve reports
as of September 30, 1997, such wells will account for approximately 72% of the
Company's production during the fourth quarter of 1997 on an Mcfe basis. The
occurrence of mechanical problems, storms, or other events that cause
curtailment or cessation of production from such wells could have a material
adverse effect on the Company. Basin will remain vulnerable to a
disproportionate impact of delays or interruptions of production from these
wells until it develops a more diversified production base including additional
properties.
REPLACEMENT OF RESERVES
Except to the extent that Basin conducts successful development,
exploitation or exploration activities or acquires properties containing proved
reserves, the proved reserves of Basin will decline. The rate of decline depends
upon reservoir characteristics and varies from the steep decline rate
characteristic of Gulf of Mexico reservoirs, where Basin has most of its
production, to the relatively slow decline rate characteristic of the long-lived
fields in the Rocky Mountain region, where the Company's other properties are
located. Basin's future success depends upon its ability to find, develop and/or
acquire additional oil and gas reserves at prices that permit profitable
operations. The market for acquiring proved reserves is extremely competitive,
and the Company may not be able to buy reserves for development and exploitation
at prices it considers to be reasonable or within its budgets. The cost of
drilling, completing and operating wells may vary significantly from initial
estimates. Basin's drilling operations may be unsuccessful or may be curtailed,
delayed or canceled as a result of numerous factors not within Basin's control,
including but not limited to title problems, weather conditions, compliance with
governmental requirements, shortage of capital, mechanical difficulties and
shortages or delays in the delivery of drilling rigs or other equipment.
Accordingly, there can be no assurance that Basin's acquisition, development,
exploitation and exploration activities will result in reserves added at
acceptable costs.
DEPENDENCE ON KEY PERSONNEL; LIMITED HISTORY OF OPERATIONS IN THE GULF OF MEXICO
Prior to the opening of its regional office in late 1995 in Houston, Texas,
Basin had conducted no previous operations in the Gulf of Mexico. This operating
area is highly competitive and the Company's success in its activities there
will depend on its ability to attract and retain geoscientists and other
professional staff with extensive experience operating in the area. The
Company's Houston office currently has a staff that includes seven geoscientists
and petroleum engineers plus three engineering consultants, all of whom are
experienced in Gulf of Mexico operations. Basin also depends to a large extent
on the services of its founder and CEO, Michael Smith, and certain other senior
management personnel. Loss of any of these personnel could have a material
adverse impact on the Company's ability to compete.
ACQUISITION RISKS
Acquisitions of producing oil and gas properties have been a key element of
Basin's success, and Basin will continue to seek acquisitions in the future.
Even though Basin performs a review of the properties in connection with its
acquisitions which it believes is consistent with industry practices, the
resulting assessments are necessarily inexact and their accuracy inherently
uncertain, and such reviews may not reveal all existing or potential problems,
nor will it necessarily permit the Company to become sufficiently
S-12
<PAGE>
familiar with the properties to fully assess their merits and deficiencies.
Inspections may not always be performed on every well, and structural and
environmental problems are not necessarily observable even when an inspection is
undertaken. Contractual indemnities may not be obtainable, and Basin may be
required to assume the risks of the physical condition of the properties in
addition to the risk that the properties may not perform in accordance with the
Company's expectations.
PERIOD-TO-PERIOD COMPARISONS
From 1992 through 1994, the Company's operations were focused in the D-J
Basin, which was one of the most active drilling areas in the United States. The
Company implemented a significant redirection of its business strategy and
operations between late-1995 and mid-1996 by selling its D-J Basin assets,
including approximately 70% of the Company's estimated proved reserves, and
establishing operations in the shallow waters of the Gulf of Mexico.
Accordingly, period-to-period comparisons of results of operations and financial
data may not be meaningful or provide a clear or accurate indication of future
results.
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. Basin 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 Basin had conducted all of its previous
operations.
FUTURE CAPITAL REQUIREMENTS
Basin makes, and will continue to make, substantial capital expenditures for
the exploitation, exploration, acquisition and production of oil and gas
reserves. Historically, the Company has financed these expenditures primarily
with cash generated by operations and proceeds from bank borrowings. The Company
currently estimates that its aggregate capital expenditures for the balance of
1997 and 1998 will be between $60 million and $80 million, excluding
acquisitions. Basin believes that it will have sufficient cash from operations,
the proceeds of the Offering and borrowings under its credit facility to fund
such planned capital expenditures. If revenue or the Company's borrowing base
decrease as a result of lower oil and gas prices, operating difficulties or
declines in reserves or any other reason, the Company may have limited ability
to expend the capital necessary to undertake or complete future drilling
programs. In addition, Basin plans to continue to evaluate acquisitions to
increase its reserves and to provide additional drilling prospects. There can be
no assurance that additional debt or equity financing or cash generated by
operations will be available to meet these requirements, See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources."
ESTIMATES OF RESERVES AND RELATED DATA
Numerous uncertainties are 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 in this Prospectus Supplement or incorporated herein
S-13
<PAGE>
by reference represent only estimates based on available geological,
geophysical, production and engineering data, the extent, quality and
reliability of which vary. Oil and gas reserve engineering is a subjective
process of estimating accumulations of oil and gas that cannot be measured in an
exact manner. The accuracy of any reserve estimate is a function of the quality
and quantity of available data, engineering and geological interpretation and
judgment. In addition, the estimates of future net cash flow from proved
reserves of the Company and the present value thereof are based upon certain
assumptions about future production levels, prices, costs and participation, if
any, by third parties in the development of the Company's reserves that may not
prove correct over time, for reasons which may or may not be under the control
of or known to the Company. Actual future production, revenues, taxes,
development expenditures, operating expenses, quantities of recoverable reserves
and the value of cash flows from such reserves may vary significantly from the
assumptions and estimates set forth herein. In addition, reserve engineers may
make different estimates of reserves and cash flow based on the same available
data. In calculating reserves on a Mcfe basis, oil was converted to gas
equivalent at the ratio of six Mcf of gas to one Bbl of oil. While this ratio
approximates the energy equivalency of gas to oil on a Btu basis, it may not
represent the relative prices received by Basin on the sale of its oil and gas
production.
Approximately 39% of the Company's total proved reserve quantities at
September 30, 1997 were undeveloped, estimates of which are by their nature less
certain. Recovery of such reserves will require significant capital expenditures
and successful drilling operations. The reserve reports as of September 30, 1997
assume that aggregate capital expenditures by the Company of approximately $29.2
million through 2004 will be required to develop such reserves. No assurance can
be given that the estimated costs are accurate, that development will occur as
scheduled or that the results will be as estimated. See "Business and
Properties--Oil and Gas Reserves."
The PV-10 Values referred to in this Prospectus Supplement should not be
construed as the current market value of the estimated oil and gas reserves
attributable to the Company's properties. In accordance with applicable
requirements of the SEC, the PV-10 Value is generally based on prices and costs
as of the date of the estimate, whereas actual future prices and costs may be
materially higher or lower. In addition, the 10% discount factor, which is
required by the SEC to be used in calculating discounted future net cash flows
for reporting purposes, is not necessarily the most appropriate discount factor
based on interest rates in effect from time to time and risks associated with
the Company or the oil and gas industry in general.
OPERATING HAZARDS
The oil and gas business involves a variety of operating risks, including
the risk of fire, explosion, blow-out, pipe failure, casing collapse, stuck
tools, abnormally pressured formations and environmental hazards such as oil
spills, gas leaks, pipeline ruptures and discharges of toxic gases, the
occurrence of any of which could result in substantial losses to Basin due to
injury and loss of life, loss of or damage to wellbores and/ or drilling or
production equipment, costs of overcoming downhole problems, severe damage to
and destruction of property, natural resources and equipment, pollution and
other environmental damage, clean-up responsibilities, regulatory investigation
and penalties and suspension of operations. Gathering systems and processing
facilities are subject to many of the same hazards and any significant problems
related to those facilities could adversely affect Basin's ability to market its
production. Moreover, offshore operations are subject to a variety of operating
risks peculiar to the marine environment, such as hurricanes or other adverse
weather conditions. Basin maintains insurance against some, but not all,
potential risks; however, there can be no assurance that such insurance will be
adequate to cover any losses or exposure for liability. Insurance may not cover
downhole operating risks, such as the costs of retrieving stuck equipment.
Furthermore, Basin cannot predict whether insurance will continue to be
available at premium levels that justify its purchase or whether insurance will
be available at all to cover the risks faced by the Company.
S-14
<PAGE>
PRINCIPAL STOCKHOLDER
Basin's principal stockholder, Michael S. Smith, together with members of
his immediate family and trustees for their benefit, will beneficially own
approximately 22.9% of Basin's outstanding shares following the Offering. As a
result, Mr. Smith is in a position to substantially influence the outcome of
stockholder votes on the election of directors and other matters. In addition,
if Mr. Smith were to sell a significant number of his shares, the prevailing
market price of the Common Stock could be adversely affected.
S-15
<PAGE>
USE OF PROCEEDS
Net proceeds from this Offering to the Company are estimated to be
approximately $43.5 million ($50.0 million if the Underwriters' over-allotment
options are exercised in full), after deducting the underwriting discount and
estimated offering expenses, assuming an offering price of $18 9/16 per share.
The Company intends to use such net proceeds to repay substantially all amounts
outstanding under its Credit Facility (defined below), to fund exploration and
development activities, for possible future acquisitions of oil and gas
properties and for general corporate purposes. Pending such uses, Basin intends
to invest the net proceeds from the Offering in government securities and other
short-term, investment grade, interest-bearing instruments.
Basin will use the net proceeds of the Offering to repay borrowings under
its Amended and Restated Credit Agreement, dated August 6, 1996 (the "Credit
Facility"), between the Company and a group of banks. Amounts repaid under the
revolving loan provisions of the Credit Facility will be available for re-
borrowing (subject to borrowing base limitations and other restrictions) until
the Credit Facility is converted to a four-year term loan on August 1, 1999. As
of September 30, 1997, borrowings of $23 million were outstanding under the
Credit Facility, with a weighted average interest rate of 6.3%. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources--Credit Facility."
The Company will not receive any of the proceeds from the sale of shares by
the Selling Stockholder. See "Selling Stockholder."
S-16
<PAGE>
CAPITALIZATION
The following table sets forth the capitalization of Basin as of September
30, 1997, and as adjusted to give effect to the issuance of the shares of Common
Stock being offered by the Company hereby and the application of the estimated
net proceeds therefrom (at an assumed offering price of $18 9/16 per share).
This table should be read in conjunction with the Company's historical
consolidated financial statements and the notes thereto. Also see "Use of
Proceeds."
<TABLE>
<CAPTION>
AS OF SEPTEMBER 30,
1997
----------------------
ACTUAL AS ADJUSTED
--------- -----------
(UNAUDITED)
(DOLLARS IN THOUSANDS)
<S> <C> <C>
Cash.......................................................................... $ 1,314 $ 21,764
--------- -----------
--------- -----------
Long-term debt(1)............................................................. 23,092 92
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; 10,813,000
shares and 13,313,000 shares issued and outstanding, respectively(2)...... 108 133
Additional paid-in capital.................................................. 59,401 102,826
Retained earnings............................................................. 9,961 9,961
Common stock held in treasury, at cost, 56,000 shares......................... (136) (136)
--------- -----------
Total stockholders' equity................................................ 69,334 112,784
--------- -----------
Total capitalization...................................................... $ 92,426 $ 112,876
--------- -----------
--------- -----------
</TABLE>
- ------------------------
(1) Does not reflect indebtedness incurred under the Credit Facility subsequent
to September 30, 1997 of $4.0 million.
(2) Excludes 784,000 shares of Common Stock reserved for issuance upon the
exercise of outstanding stock options (at a weighted-average exercise price
of $6.82 per share) granted under the Company's Equity Incentive Plan and
Director's Stock Option Plan. Also excludes 300,000 shares of Common Stock
subject to outstanding warrants having an exercise price of $14.00 per
share, a portion of which are owned by one of the Underwriters in this
Offering and certain of its affiliates. See "Underwriting."
S-17
<PAGE>
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
The Common Stock is traded on the Nasdaq National Market under the symbol
"BSNX." The following table sets forth, for the periods indicated, the high and
low closing sales price per share for the Common Stock as reported by the
Nasdaq.
<TABLE>
<CAPTION>
HIGH LOW
--------- ---------
<S> <C> <C>
1995
First Quarter...................................................................... $ 11.50 $ 6.38
Second Quarter..................................................................... 9.13 5.38
Third Quarter...................................................................... 7.00 4.38
Fourth Quarter..................................................................... 5.88 3.00
1996
First Quarter...................................................................... $ 5.25 $ 3.69
Second Quarter..................................................................... 6.63 5.00
Third Quarter...................................................................... 7.50 5.75
Fourth Quarter..................................................................... 7.75 5.63
1997
First Quarter...................................................................... $ 7.38 $ 6.19
Second Quarter..................................................................... 8.63 6.50
Third Quarter...................................................................... 17.13 7.81
Fourth Quarter (through October 8, 1997)........................................... 19.13 17.38
</TABLE>
On October 8, 1997, the last reported sales price on the Nasdaq National
Market was $18 9/16 per share. As of September 30, 1997, there were
approximately 120 holders of record and approximately 2,300 beneficial owners of
the Common Stock.
Basin has not in the past paid, and does not intend to pay in the
foreseeable future, cash dividends on its Common Stock. The Company currently
intends to retain earnings, if any, for the future operation and development of
its business. The Company's Credit Facility contains provisions that may have
the effect of limiting or prohibiting the payment of dividends. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources."
S-18
<PAGE>
SELECTED HISTORICAL FINANCIAL INFORMATION
The following table sets forth certain consolidated financial data for Basin
as of and for each of the periods indicated. The financial data for each year in
the five years ended December 31, 1996 are derived from the audited financial
statements of the Company. The financial data for the three and nine months
ended September 30, 1997 and 1996 are derived from the Company's unaudited
financial statements which, in the opinion of management of the Company, have
been prepared on the same basis as the annual consolidated financial statements
and include all adjustments (consisting of only normal recurring adjustments)
necessary for a fair presentation of the financial data for such periods. The
following data should be read in conjunction with "Management's Discussion and
Analysis of Financial Condition and Results of Operations," which includes a
discussion of factors materially affecting the comparability of the information
presented, and the Company's consolidated financial statements included
elsewhere in this Prospectus Supplement. The results for the three and nine
months ended September 30, 1997 are not necessarily indicative of results for
the full year. Historical financial data are not necessarily predictive of the
Company's future results of operations and financial condition.
<TABLE>
<CAPTION>
THREE MONTHS ENDED
NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30, YEAR ENDED DECEMBER 31,
-------------------- ---------------------- ------------------------------------------
1997(1) 1996 1997(1)(2) 1996 1996(2) 1995 1994 1993
--------- --------- ----------- --------- --------- --------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenue:
Oil and gas sales................. $ 6,876 $ 2,586 $ 12,630 $ 15,168 $ 18,182 $ 39,645 $ 44,226 $ 37,864
Gain on sale of assets............ -- -- -- 22,472 22,472 -- -- --
Interest and other................ 30 429 254 631 1,009 831 161 104
--------- --------- ----------- --------- --------- --------- --------- ---------
6,906 3,015 12,884 38,271 41,663 40,476 44,387 37,968
--------- --------- ----------- --------- --------- --------- --------- ---------
Costs and expenses:
Lease operating expenses.......... 1,029 819 3,065 3,823 4,776 8,196 8,642 7,105
Production taxes.................. 258 283 893 1,482 1,829 3,478 3,432 2,918
Depreciation, depletion and
amortization.................... 2,979 1,081 5,375 6,551 7,606 17,202 18,163 12,311
General and administrative, net... 838 802 2,441 3,014 3,850 5,498 4,641 4,182
Interest and other expense........ 316 27 487 2,245 2,272 6,929 3,618 3,160
Property impairment(3)............ -- -- -- -- -- 26,500 -- --
--------- --------- ----------- --------- --------- --------- --------- ---------
5,420 3,012 12,261 17,115 20,333 67,803 38,496 29,676
--------- --------- ----------- --------- --------- --------- --------- ---------
Income (loss) before income taxes,
net................................ 1,486 3 623 21,156 21,330 (27,327) 5,891 8,292
Income tax (provision) benefit...... (520) (1) (218) (5,695) (5,760) 7,784 (2,236) (3,142)
--------- --------- ----------- --------- --------- --------- --------- ---------
Net income (loss)................... $ 966 $ 2 $ 405 $ 15,461 $ 15,570 $ (19,543) $ 3,655 $ 5,150
--------- --------- ----------- --------- --------- --------- --------- ---------
--------- --------- ----------- --------- --------- --------- --------- ---------
Earnings (loss) per share........... $ 0.09 $ -- $ 0.04 $ 1.44 $ 1.45 $ (1.82) $ 0.34 $ 0.67
--------- --------- ----------- --------- --------- --------- --------- ---------
--------- --------- ----------- --------- --------- --------- --------- ---------
Weighted average common shares
outstanding........................ 10,757 10,701 10,720 10,700 10,700 10,710 10,813 7,650
OTHER FINANCIAL DATA:
Cash flow from operations before
changes in working capital......... $ 4,955 $ 1,101 $ 6,611 $ 3,432 $ 5,680 $ 17,050 $ 24,973 $ 20,894
Net cash provided by operating
activities......................... $ 4,792 $ 2,751 $ 3,549 $ 4,488 $ 4,909 $ 10,320 $ 29,261 $ 18,555
Capital additions................... $ 13,067 $ 15,587 $ 47,267 $ 25,694 $ 27,741 $ 17,782 $ 62,321 $ 70,351
EBITDA(4)........................... $ 4,781 $ 1,111 $ 6,485 $ 7,480 $ 8,736 $ 23,304 $ 27,672 $ 23,763
<CAPTION>
1992
---------
<S> <C>
INCOME STATEMENT DATA:
Revenue:
Oil and gas sales................. $ 21,758
Gain on sale of assets............ --
Interest and other................ 353
---------
22,111
---------
Costs and expenses:
Lease operating expenses.......... 5,418
Production taxes.................. 1,794
Depreciation, depletion and
amortization.................... 5,839
General and administrative, net... 2,997
Interest and other expense........ 1,801
Property impairment(3)............ --
---------
17,849
---------
Income (loss) before income taxes,
net................................ 4,262
Income tax (provision) benefit...... (753)
---------
Net income (loss)................... $ 3,509
---------
---------
Earnings (loss) per share........... $ 0.57
---------
---------
Weighted average common shares
outstanding........................ 6,188
OTHER FINANCIAL DATA:
Cash flow from operations before
changes in working capital......... $ 9,916
Net cash provided by operating
activities......................... $ 8,948
Capital additions................... $ 28,243
EBITDA(4)........................... $ 11,902
</TABLE>
FOOTNOTES ON NEXT PAGE
S-19
<PAGE>
<TABLE>
<CAPTION>
AS OF SEPTEMBER 30,
1997
---------------------- AS OF DECEMBER 31,
AS -----------------------------------------------------
ACTUAL ADJUSTED(5) 1996(1) 1995 1994 1993 1992
--------- ----------- --------- --------- --------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Working capital (deficit)......... $ (2,159) $ 18,291 $ 19,178 $ (2,211) $ (5,646) $ 106 $ (102)
Net property and equipment........ 100,970 100,970 54,800 134,598 165,807 116,133 64,662
Total assets...................... 113,250 133,700 84,957 146,651 184,855 131,520 75,161
Long-term debt, net of current
portion.......................... 23,092 92 218 77,172 77,199 41,819 36,606
Total stockholders' equity........ 69,334 112,784 68,751 53,287 72,575 67,183 24,701
</TABLE>
- --------------------------
(1) For the month of September 1997, which included the first full month of
production from the Company's Eugene Island Block 65 property, Basin's
revenue, income before income taxes and cash flow from operations before
changes in working capital were $3,550,000, $1,219,000 and $2,513,000
(exclusive of a change in estimate of current taxes payable for fiscal
1996), respectively.
(2) Oil and gas sales and certain expenses decreased from 1995 to 1996 and from
the first nine months of 1996 to the first nine months of 1997 as a result
of the D-J Sales. As of December 31, 1995, the Company's assets in the D-J
Basin represented approximately two-thirds of the Company's producing wells
and 70% of its proved oil and gas reserves. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Results of
Operations."
(3) During 1995, Basin recognized a property impairment 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. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Results of Operations" and the Company's consolidated financial
statements.
(4) EBITDA is defined as income before interest, income taxes, depreciation,
depletion and amortization, property impairment and gain on sale of assets.
EBITDA is a financial measure commonly used in the Company's industry and
should not be considered in isolation or as a substitute for net income, net
cash provided by operating activities or other income or cash flow data
prepared in accordance with generally accepted accounting principles or as a
measure of a company's profitability or liquidity. Because EBITDA excludes
some, but not all, items that affect net income and may vary among
companies, the EBITDA presented above may not be comparable to similarly
titled measures of other companies.
(5) As adjusted for the Offering and the application of the estimated net
proceeds to the Company therefrom. See "Capitalization."
S-20
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 D-J Basin.
The Company subsequently expanded into other areas within the Rocky Mountain
region and initiated exploration activities. By December 31, 1994, the Company's
estimated net proved oil and gas reserves had grown to 247 Bcfe, of which 169
Bcfe, or 68.4%, were located in the D-J Basin.
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 bank line of credit. Each of these factors was
exacerbated by depressed regional gas prices.
In response to these developments, 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 D-J Sales; (iii)
establishment of a Houston-based Gulf of Mexico exploration team through the
hiring of senior 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. Since
the D-J Sales, Basin has significantly increased its proved reserves and
production base through successful Gulf of Mexico drilling activity and
acquisitions, and it has established a sizeable inventory of Gulf of Mexico
leaseholds and prospects for future exploratory drilling.
The first production resulting from Gulf of Mexico activities was achieved
in August 1997 when Basin brought on-line two wells on Eugene Island Block 65,
which the Company had drilled earlier in the year. As a result, the Company's
average net daily production increased from 11.3 MMcfe per day during the first
half of 1997 to 43.6 MMcfe per day in September 1997, which included the first
full month of production from Eugene Island Block 65. At September 30, 1997, the
Company owned interests in five additional Gulf of Mexico wells that were being
completed or were temporarily suspended pending additional development. Four of
such wells are expected to commence production shortly before or during the
first quarter of 1998. The fifth well is expected to commence production after
mid-1998. The Company's cash flow has increased significantly since commencement
of production at Eugene Island Block 65 and is expected to increase further as
these additional Gulf of Mexico wells are brought on-line.
During the first nine months of 1997, the Company's capital expenditures
totaled approximately $52.3 million, including approximately $27.0 million on
exploration and development and $25.3 million on acquisitions of proved
properties and exploratory leaseholds. The Company currently estimates that it
will invest between $60 million and $80 million on exploration and development
activities between October 1, 1997 and the end of 1998, and will also continue
to seek to acquire properties with proved reserves and exploitation or
exploration potential.
Basin will use the net proceeds of the Offering to repay amounts borrowed
under its Credit Facility and increase working capital. The Company believes
that projected cash flow from operations, together with working capital and
borrowing capacity, each as adjusted for the Offering, will be sufficient to
fund its operations and capital expenditures through the end of 1998.
S-21
<PAGE>
Basin's revenue and results of operations are significantly affected by
changes in oil and gas prices. Assuming level production, the Company's total
revenue would generally be higher in the first and fourth quarters due to higher
natural gas prices typically resulting from greater demand during colder months.
In addition, because the Company's operations were focused in the D-J Basin
prior to 1996, period-to-period comparisons of results of financial data may not
be meaningful or an indication of future results. The following discussion
should be read in conjunction with Basin's Consolidated Financial Statements and
the Notes thereto included elsewhere in this Prospectus Supplement.
RESULTS OF OPERATIONS
THREE AND NINE MONTHS ENDED SEPTEMBER 30, 1997 AND 1996
REVENUE. Revenue for the three months ended September 30, 1997, was $6.9
million, an increase of $3.9 million, or 129%, as compared to the same period in
1996. Revenue for the nine months ended September 30, 1997, of $12.9 million
represented a decrease of $2.9 million, or 18%, from amounts reported for the
same period in 1996, excluding a $22.5 million gain recognized in connection
with the D-J Sales in the second quarter of 1996. The following table reflects
the Company's average realized oil and gas prices, including the effects of
hedging, and its average daily oil and gas production for the periods presented:
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------------------------- -----------------------------------
1997 1996 % CHANGE 1997 1996 % CHANGE
--------- --------- ------------- --------- --------- -------------
<S> <C> <C> <C> <C> <C> <C>
Average price:
Oil (per Bbl)............................... $ 18.59 $ 21.10 (12) $ 18.88 $ 19.55 (3)
Gas (per Mcf)............................... $ 2.45 $ 1.22 101 $ 2.37 $ 1.39 71
Average daily production:
Oil (Bbl)................................... 1,600 1,064 50 1,304 1,699 (23)
Gas (Mcf)................................... 18,353 4,664 294 9,121 15,886 (43)
Mcfe........................................ 27,953 11,048 153 16,945 26,080 (35)
</TABLE>
The increase in average daily production for the three months ended
September 30, 1997 was attributable to the commencement of production from two
wells on Eugene Island Block 65 in the Gulf of Mexico in mid-August 1997.
Production from these two wells averaged 26,747 Mcf and 858 Bbl of condensate,
or 31,895 Mcfe, per day net to Basin's interest during September 1997, the
wells' first full month of production, and for the quarter totaled 1,557 MMcfe,
impacting average daily production for the full quarter by 17,305 Mcfe. The
decrease in average daily production for the nine months ended September 30,
1997 was primarily attributable to the D-J Sales. In the two transactions
comprising the D-J Sales, the Company sold all of its assets in the D-J Basin.
As of December 31, 1995, these assets represented approximately two-thirds of
the Company's producing wells and 70% of its proved oil and gas reserves. In
conjunction with the second transaction, which closed in June 1996, the Company
recognized a $22.5 million gain. Excluding the production and sales from such
D-J Basin properties, average oil and gas prices and average daily oil and gas
production for the nine months ended September 30, 1997 and 1996 were:
<TABLE>
<CAPTION>
NINE MONTHS
ENDED SEPTEMBER 30,
-------------------------------------
1997 1996 % CHANGE
--------- --------- ---------------
<S> <C> <C> <C>
Average price:
Oil (per Bbl)................................................ $ 18.88 $ 20.35 (7)
Gas (per Mcf)................................................ $ 2.37 $ 1.20 98
Average daily production:
Oil (Bbl).................................................... 1,304 1,168 12
Gas (Mcf).................................................... 9,121 4,909 86
Mcfe......................................................... 16,945 11,917 42
</TABLE>
S-22
<PAGE>
LEASE OPERATING EXPENSES. Lease operating expenses for the three and nine
months ended September 30, 1997, were $1.0 million and $3.1 million,
representing an increase of $0.2 million, or 26%, and a decrease of $0.8
million, or 20%, respectively, compared to the same periods in 1996. Production
costs per Mcfe produced during the three and nine months ended September 30,
1997, were $0.40 and $0.66, compared to $0.81 and $0.54, respectively, in 1996.
The higher costs per Mcfe during the nine months ended September 30, 1997 were
caused primarily by the increased portion of the Company's total active wells in
the Rocky Mountain region after the D-J Sale that are oil wells, with typically
higher unit operating costs, and the contribution from Eugene Island Block 65
for a relatively small portion of the nine-month period. The lower costs per
Mcfe during the three months ended September 30, 1997 were due to a contribution
from Eugene Island Block 65 for approximately one-half of the period.
PRODUCTION TAXES. Production taxes for the three and nine months ended
September 30, 1997, were $0.3 million and $0.9 million, decreases of $25,000, or
9%, and $0.6 million, or 40%, respectively, compared to the same periods in
1996. Production taxes as a percent of oil and gas sales for the three and nine
months ended September 30, 1997 were 3.8% and 7.1%, compared to 10.9% and 9.8%,
respectively, in 1996. The lower average tax rates were due to a portion of
sales occurring in federal waters offshore where production taxes do not apply
following the commencement of production from Eugene Island Block 65. The
proportionate impact of this is greater for the recent three-month period than
for the nine-month period.
DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and
amortization expense for the three and nine months ended September 30, 1997, was
$3.0 million and $5.4 million, representing an increase of $1.9 million, or
175%, and a decrease of $1.2 million, or 18%, respectively, compared to the same
periods in 1996. These variances are primarily attributable to variations in
production volumes in 1997 as compared to the same periods in 1996. The
depletion rate of $1.01 per Mcfe produced in the nine months ended September 30,
1997 increased from $0.82 per Mcfe average depletion rate during the same 1996
period, due primarily to additions of proved reserves in 1997 at higher costs
than the Company's historical average.
GENERAL AND ADMINISTRATIVE, NET. General and administrative expenses for
the three and nine months ended September 30, 1997 were $0.8 million and $2.4
million, respectively, reflecting an increase of $36,000 or 4%, and a decrease
of $0.6 million, or 19%, respectively, compared to the same periods in 1996. The
decrease in the nine months ended September 30, 1997 resulted primarily from
staff reductions made during the first half of 1996 and related reductions in
office rent expense attributable to the Company's relocation to smaller space in
the second half of 1996.
INTEREST EXPENSE. Interest expense for the three and nine months ended
September 30, 1997 was $0.3 million and $0.5 million, representing an increase
of $0.3 million, and a decrease of $1.8 million, or 78%, respectively, compared
to the same periods in 1996. The variances were principally attributable to
changes in average borrowings as a result of asset sales consummated during 1996
and the redeployment of capital in 1997, as summarized below:
<TABLE>
<CAPTION>
THREE MONTHS ENDED
NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------- --------------------
1997 1996 1997 1996
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Average borrowings (in thousands)..................... $ 18,255 $ 663 $ 8,625 $ 34,080
Average interest rate on borrowings................... 6.5% 6.3% 6.7% 8.0%
</TABLE>
INCOME TAX PROVISION. The income tax provision for 1997 approximates the
amount that would be calculated by applying statutory income tax rates to the
income before income taxes. The differences between the income tax provisions
for the three and nine months ended September 30, 1996, and the amounts which
would be calculated by applying statutory income tax rates to income before
income taxes are due primarily to reversal of a previously established $2.2
million deferred tax asset valuation allowance.
S-23
<PAGE>
The current provision for income taxes was decreased, and the deferred provision
was increased, by approximately $0.6 million in both the three-month and
nine-month periods ended September 30, 1997, due to a change in estimate of
current taxes payable for fiscal 1996.
YEARS ENDED DECEMBER 31, 1996 AND 1995
REVENUE. Excluding a $22.5 million gain on sale of assets recognized during
1996, revenue for 1996 was $19.2 million, representing a decrease of $21.3
million, or 53%, as compared to 1995. The following table reflects the Company's
average oil and gas prices and its average daily oil and gas production for the
years presented:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------
1996 1995 % CHANGE
--------- --------- -------------
<S> <C> <C> <C>
Average price:
Oil (per Bbl)................................................ $ 20.03 $ 17.02 18
Gas (per Mcf)................................................ $ 1.44 $ 1.56 (8)
Average daily production:
Oil (Bbl).................................................... 1,540 3,160 (51)
Gas (Mcf).................................................... 13,050 35,154 (63)
Mcfe......................................................... 22,290 54,114 (59)
</TABLE>
The decreases in average daily production were primarily attributable to the
combined effects of the D-J Sales of producing properties during 1996 and 1995
and natural production declines. As more fully described below under Liquidity
and Capital Resources, the Company consummated two transactions during 1996 in
which all of its assets in the D-J Basin were sold. As of December 31, 1995,
these assets represented approximately two-thirds of the Company's producing
wells and 70% of its proved oil and gas reserves. In conjunction with the second
transaction, the Company recognized a $22.5 million gain. Excluding production
and sales from such D-J Basin properties, average oil and gas prices and average
daily oil and gas production for the periods presented were:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------
1996 1995 % CHANGE
--------- --------- -------------
<S> <C> <C> <C>
Average price:
Oil (per Bbl)................................................ $ 20.32 $ 17.61 15
Gas (per Mcf)................................................ $ 1.33 $ 1.09 22
Average daily production:
Oil (Bbl).................................................... 1,118 1,341 (17)
Gas (Mcf).................................................... 4,871 5,517 (12)
Mcfe......................................................... 11,579 13,563 (15)
</TABLE>
During 1995, the Company also recognized gas revenue for payments received
with respect to transferred Section 29 tax credits in the amount of $2.9
million.
Other revenue in 1995 was primarily derived from a small processing facility
that was decommissioned late in the year. In 1996, other revenue related mainly
to interest income on cash equivalents held after the D-J Sales.
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 are oil wells, with typically higher unit
operating costs, following the sale of the D-J Basin assets.
S-24
<PAGE>
PRODUCTION TAXES. Production taxes for 1996 were $1.8 million, a decrease
of $1.6 million, or 47%, compared to 1995. Production taxes as a percent of oil
and gas sales for 1996 were 10.1%, compared to 8.8% in 1995. The increased
average tax rate was due to a greater portion of sales occurring in higher-tax
jurisdictions in 1996.
DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and
amortization expense for 1996 was $7.6 million, a decrease of $9.6 million, or
56%, as compared to 1995. The decrease was primarily attributable to the lower
production volumes in 1996 as compared to 1995. The depletion rate of $.82 per
Mcfe produced in 1996 was slightly lower than the $.84 per Mcfe average
depletion rate during 1995.
PROPERTY IMPAIRMENT. During 1995, the Company recognized a property
impairment charge of $26.5 million, as the result of the capitalized costs of
its oil and gas properties exceeding a "ceiling" on such costs computed in
accordance with prescribed accounting guidelines.
GENERAL AND ADMINISTRATIVE, NET. General and administrative expenses for
1996 were $3.9 million, a decrease of $1.6 million, or 30%, as compared to 1995.
The decreases resulted primarily from staff reductions made during the second
half of 1995 and the first half of 1996 and partially due to reductions in
office rent expense as a result of relocating and decreasing the size of the
corporate headquarters.
INTEREST EXPENSE. Interest expense for 1996 totaled $2.3 million
representing a decrease of $4.2 million, or 65%, as compared to 1995. The
decrease was principally attributable to lower average borrowings as a result of
the use of proceeds from the D-J Sales to retire debt during 1996, as summarized
below:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER
31,
--------------------
1996 1995
--------- ---------
<S> <C> <C>
Average borrowings (in thousands)....................................... $ 28,200 $ 78,800
Average interest rate on borrowings..................................... 8.0% 7.3%
</TABLE>
INCOME TAX BENEFIT (PROVISION). The difference between the income tax
provision for 1996 and the income tax benefit for 1995, and the amounts that
would be calculated by applying statutory income tax rates to income before
income taxes is due primarily to the 1996 reversal of the $2.2 million deferred
tax asset valuation allowance established during 1995.
YEARS ENDED DECEMBER 31, 1995 AND 1994
REVENUE. Revenue for 1995 was $40.5 million, a decrease of $3.9 million, or
9%, as compared to 1994. The following table reflects the Company's average oil
and gas prices and its average daily oil and gas production for the years
presented:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------
1995 1994 % CHANGE
--------- --------- -------------
<S> <C> <C> <C>
Average price:
Oil (per Bbl)................................................ $ 17.02 $ 15.63 9
Gas (per Mcf)................................................ $ 1.56 $ 1.69 (8)
Average daily production:
Oil (Bbl).................................................... 3,160 3,501 (10)
Gas (Mcf).................................................... 35,154 39,389 (11)
Mcfe......................................................... 54,114 60,395 (10)
</TABLE>
The declines in production are partially attributable to the sale of
marginal properties during 1995. Lower production also resulted from normal
depletion-related declines that were not fully offset by new drilling and
recompletion activities. The Company recognized gas revenues for payments
received with
S-25
<PAGE>
respect to transferred Section 29 tax credits, in the amounts of $2.9 million
and $2.1 million for the years ended December 31, 1995 and 1994, respectively.
LEASE OPERATING EXPENSES. Lease operating expenses for 1995 were $8.2
million, a decrease of $0.4 million, or 5%, compared to 1994. Lease operating
costs per Mcfe produced during 1995 increased from an average $.42 compared to
$.39 in 1994, primarily due to a decline in the number of new wells brought on
line. New wells typically have relatively high initial production rates and
lower average unit production costs than more mature properties.
PRODUCTION TAXES. Production taxes for 1995 were $3.5 million, an increase
of $46,000, or 1%, compared to 1994. Production taxes as a percent of oil and
gas sales for 1995 were 8.8%, compared to 7.8% in 1994. The increased average
tax rate was due to a greater portion of sales occurring in higher-tax
jurisdictions in 1995.
DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and
amortization expense for 1995 was $17.2 million, a decrease of $1.0 million, or
5%, as compared to 1994. The decrease was attributable to the lower production
volumes in 1995 as compared to 1994, as the average depletion rate of $.84 per
Mcfe produced in 1995 was higher than the $.77 per Mcfe rate in 1994. The
increase reflects investment costs per Mcfe of reserves added during the second
half of 1994 and in 1995 which were above the Company's historical average, as
well as a reduction in estimated proved reserves at December 31, 1995 due, in
part, to the effects of using lower gas prices in determining economic
production limits.
PROPERTY IMPAIRMENT. During 1995, the Company recognized a property
impairment charge of $26.5 million, as the result of the capitalized costs of
its oil and gas properties exceeding a "ceiling" on such costs computed in
accordance with prescribed accounting guidelines.
GENERAL AND ADMINISTRATIVE, NET. General and administrative expenses for
1995 were $5.5 million, an increase of $0.9 million, or 18%, as compared to
1994. The increase is primarily due to smaller recoveries from third-party
working interest owners and nonrecurring charges of $0.5 million related to
staff reductions, settlement of a legal dispute, and an unsuccessful corporate
acquisition effort. The lower recoveries resulted from the Company's acquisition
in late-1994 of additional working interests in certain properties that it
operates and reduced billings for drilling and completion overhead due to a less
active property development program in 1995. Decreases in gross general and
administrative expenses resulting from late-1995 reductions in office staff and
other administrative costs had minimal impact in 1995.
INTEREST EXPENSE. Interest expense for 1996 totaled $6.4 million, an
increase of $2.8 million, or 78%, as compared to 1994. This increase was due to
the combined effects of increased average borrowings and higher interest rates,
as summarized below:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER
31,
--------------------
1995 1994
--------- ---------
<S> <C> <C>
Average borrowings (in thousands)....................................... $ 78,800 $ 55,600
Average interest rate on borrowings..................................... 7.3% 5.7%
</TABLE>
INCOME TAX BENEFIT (PROVISION). The difference between the income tax
benefit for 1995, and the amount that would be calculated by applying statutory
income tax rates to the loss before income taxes is due to the establishment of
a $2.2 million deferred tax asset valuation allowance during 1995.
S-26
<PAGE>
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.
In the D-J Sales, the Company sold its D-J Basin assets for a total of
$123.5 million in two transactions in March and June, 1996, respectively. A
portion of the proceeds from the D-J Sales was used to repay substantially all
of the Company's debt and as of June 30, 1996, the Company had $24.9 million of
net working capital, including $37.6 million of cash, and long-term debt of $0.4
million. The Company has funded subsequent capital expenditures with the
beginning working capital, net borrowings under its Credit Facility and cash
flow from operations.
As of September 30, 1997, the Company had a working capital deficit of $2.2
million. On the same date, borrowings under the Company's Credit Facility
totaled $23 million, leaving unutilized capacity under the line of $9.5 million.
The borrowing base is scheduled to be redetermined as of November 1, 1997 and
the Company anticipates that it will be increased from the current level of
$32.5 million at that time.
The Company believes that expected cash flow from operations, together with
working capital and borrowing capacity, each as adjusted for the Offering, will
be sufficient to fund its operations and capital expenditures through the end of
1998.
PRODUCTION AND CASH FLOW. The D-J Basin properties represented
approximately 70% of the Company's oil and gas reserves and production as of
December 31, 1995. 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 1.0 Bcfe, or 11,000
Mcfe per day. For the same period, net cash flow 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 which 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 September 30, 1997, the Company's production
increased by approximately 160%, to 2.6 Bcfe, or approximately 28,000 Mcfe per
day, and net cash flow from operations before changes in working capital
increased to $5.0 million, primarily due to commencement of production from two
wells that the Company drilled and completed earlier in the year on Eugene
Island Block 65. From commencement of production on August 11, 1997 through
September 30, 1997, combined gross production from these two wells averaged 45.9
MMcf and 1,367 Bbl of condensate per day. Through an acquisition, the Company
increased its before pay-out net revenue interest ("NRI") in Eugene Island Block
65 from 50.9% in August 1997 to 58.2% beginning September 1997. The Company's
NRI will increase to 62.3% upon reaching project payout.
The Company anticipates that its net production in the fourth quarter of
1997 will exceed net production in the third quarter of 1997, primarily due to
an expected full quarter's contribution from the Eugene Island Block 65
property. As of September 30, 1997, the Company also owned interests in five
other Gulf of Mexico discovery wells (one of which Basin acquired after the well
was drilled) that are expected to be brought on-line in the near future. The
Company expects that four wells, one each on East Cameron Block 378 (38.6% NRI),
Eugene Island Block 49 (80.8% NRI), Eugene Island Block 83 (48.5% NRI), and West
Cameron Block 56 (49.8% NRI), will commence production shortly before or during
the first quarter of 1998. A well on West Delta Block 122 (17.7% NRI) is
expected to begin producing after mid-1998.
S-27
<PAGE>
The Company expects that its future net cash flow will be determined
substantially by production levels and oil and gas prices, since it does not
expect operating costs to rise proportionally with increased production. Certain
costs per unit of production have improved recently as the Company has commenced
production in the Gulf of Mexico, and are expected to continue to improve as
additional Gulf of Mexico production is brought on-line. Production taxes are
not applicable to properties in federal waters. Lease operating expenses per
unit tend 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 significantly as Gulf of Mexico production
increases.
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 purpose of these transactions is to limit the Company's exposure
to future oil and gas price declines and achieve a more predictable cash flow.
Such contracts also limit the benefits the Company would realize if prices
increase.
Basin has entered into hedging contracts for the contract volumes, average
NYMEX crude oil prices, and time periods summarized below:
<TABLE>
<CAPTION>
FIXED PRICE OR
BBLS/MONTH COLLAR RANGE TIME PERIOD
- ----------- --------------- ----------------
<S> <C> <C>
10,000 $18.32 10/97-12/97
10,000 $19.50-$24.35 10/97-12/97
10,000 $23.45 11/97-01/98(1)
10,000 $21.30 11/97-10/98
</TABLE>
- ------------------------
(1) The counterparty to this contract has an option to extend the time period
for this hedge for six months on January 30, 1998
Basin has also entered into a gas collar arrangement covering 450,000 MMBtu
per month for the months of October 1997 through April 1998, but the Company
concurrently has call options on an equivalent volume of gas, which limit the
amount of potential price increases that might otherwise be foregone due to the
collar ceiling. The gas collar's NYMEX floor and ceiling prices vary by month
over the seven-month term, averaging $2.094 and $2.536, respectively, and the
Company's call option for each month is at a strike price $0.29 above the
applicable contract ceiling price.
CREDIT FACILITY. The Credit Facility, with a bank group led by NationsBank
of Texas, N.A. provides for the interest rate on 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
revolving Credit Facility, established at $32.5 million in June 1997, is
scheduled to be redetermined as of November 1, 1997 and generally at six-month
intervals thereafter until converted into a term loan. Until the next borrowing
base redetermination, if borrowings under the line of credit exceed $25 million,
the applicable interest rate will be increased by 0.5%. Due to commencement of
production on Eugene Island Block 65 and the addition of proved reserves since
the last redetermination date, management anticipates that the borrowing base
will be increased upon redetermination. At September 30, 1997, the principal
balance outstanding under the facility was $23 million. The Credit Facility
contains various covenants, including ones that could limit the Company's
ability to incur debt, dispose of assets, pay dividends, or repurchase stock.
Pursuant to the
S-28
<PAGE>
Credit Facility, the Company's onshore producing properties (other than
Jepson-Holler Draw) are subject to mortgages in favor of the banks, and the
Company's offshore 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 activities, 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 estimates its
capital expenditures for exploration, development and exploitation will be
approximately $45 million in 1997. Although the Company does not specifically
budget for acquisitions of properties with proved and probable reserves, such
acquisitions are pursued as an integral part of the Company's overall business
strategy. During the first nine months of 1997, Basin completed approximately
$20 million of acquisitions. Including acquisitions to date, estimated capital
expenditures for 1997 will total approximately $65 million, subject to potential
increase for additional acquisitions or acceleration of development of
additional exploratory discoveries.
The Company's capital expenditures totaled approximately $52.3 million
during the first nine months of 1997. Of this amount, the Company invested $6.0
million in Rocky Mountain properties, primarily for development and exploitation
operations, and $46.3 million in properties and activities in the Gulf of
Mexico. The Gulf of Mexico investments included approximately $18 million for
two acquisitions of proved and probable reserves. The balance of expenditures in
the Gulf of Mexico was primarily for: acquisition of seismic data and
leaseholds; the drilling of nine wells, one of which was in progress at the
beginning of the year and one of which was in progress at the end of the period;
completion operations on six wells, not all of which were completed by the end
of the quarter; and production facilities for Eugene Island Block 65, which
commenced production in August 1997, and Eugene Island Block 83, where such
facilities will be installed to develop a successful exploratory well that the
Company recently drilled.
Anticipated capital expenditures in the fourth quarter of 1997 primarily
relate to: drilling activities in the Gulf of Mexico, including participation in
one well in progress at September 30, 1997 and two to four additional wells that
may be commenced during the quarter; development operations to complete and tie-
in four productive wells on East Cameron Block 378, Eugene Island Block 49,
Eugene Island Block 83, and West Cameron Block 56, respectively; and continued
exploitation of the Company's Rocky Mountain properties.
Excluding acquisitions, Basin currently estimates that capital expenditures
in 1998 will be between $45 million and $65 million. This estimate is based on
assumptions of making investments in seismic data and leaseholds in 1998
comparable to 1997, a preliminary target of participating in 12 to 15 Gulf of
Mexico exploratory wells, assumptions and estimates with regard to discoveries
on a portion of the exploratory wells and costs for related development, and
planned development of existing proved reserves. Although several locations have
been identified for planned 1998 exploratory drilling, a significant portion of
the anticipated 1998 exploration budget currently is unallocated. The Company
also intends to continue to pursue acquisitions of properties with proved and
probable reserves, 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.
S-29
<PAGE>
BUSINESS AND PROPERTIES
GENERAL
Basin Exploration, Inc. is engaged in the exploration, acquisition,
development and exploitation of oil and gas properties. The Company's oil and
gas 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 September 30, 1997, the Company's estimated net proved reserves were 60.3 Bcf
of natural gas and 8.3 MMBbl of oil, or 110.1 Bcfe, with an aggregate PV-10
Value of $151.1 million.
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.
Since commencing operations in the Gulf of Mexico at the beginning of 1996
through September 30, 1997 (giving effect to the D-J Sales as if they had
occurred at December 31, 1995), Basin has:
- Successfully drilled six of 11 exploratory wells in the Gulf of Mexico.
- Assembled 30 Gulf of Mexico exploratory prospects, 21 of which were
internally generated and 20 of which remain to be drilled.
- Completed three acquisitions of properties with proved reserves and
exploration or exploitation potential for an aggregate acquisition cost of
approximately $20 million.
- Built estimated net proved reserves in the Gulf of Mexico from 0 to 48.1
Bcfe at an average Finding Cost of approximately $1.05 per Mcfe.
- Increased total estimated net proved reserves by 76% from 62.6 Bcfe to
110.1 Bcfe.
- Increased the PV-10 Value of estimated net proved reserves by 259% from
$42.1 million to $151.1 million.
- Increased average net daily production from approximately 12.3 MMcfe to
43.6 MMcfe, primarily due to commencement of production in August 1997
from two Gulf of Mexico discovery wells, with further increases expected
from five Gulf of Mexico wells that are currently either being completed
or are temporarily suspended pending additional development.
The Company drilled three Gulf of Mexico exploratory wells in 1996, drilled
eight exploratory wells during the first nine months of 1997 and expects to
drill 12 to 15 additional exploratory wells in the Gulf of Mexico through the
end of 1998, one of which is currently being drilled. The Company currently
estimates that its aggregate capital expenditures for the balance of 1997 and
1998 will be between $60 million to $80 million, excluding acquisitions.
BUSINESS STRATEGY
Basin's business strategy is to generate strong per share growth in
reserves, production, earnings and cash flow through a balanced approach to
exploration, development and selective acquisitions of oil and gas properties.
The Company implements this strategy through the following:
FOCUS ON EXPLORATION IN THE SHALLOW WATERS OF THE GULF OF MEXICO. Basin's
exploration activities are focused in the shallow waters of the central Gulf of
Mexico, primarily offshore Louisiana. The Company believes that this region has
significant remaining undiscovered reserves and that the combination of existing
infrastructure and effectiveness of 3-D seismic will reduce exploration risk and
enhance project economics.
S-30
<PAGE>
CAPITALIZE ON TECHNICAL EXPERTISE. Basin has assembled a team of
geoscientists and petroleum engineers with substantial expertise in the shallow
waters of the Gulf of Mexico to generate prospects and evaluate acquisition
opportunities. Basin has also added senior management with substantial
acquisition experience outside the Gulf of Mexico and intends to utilize this
in-house capability in conjunction with regionally specialized geoscientists to
identify and evaluate growth opportunities through acquisitions with additional
exploration and exploitation potential.
UTILIZE ADVANCED TECHNOLOGY. Basin makes extensive use of advanced
technologies, including 3-D seismic and computer-aided exploration 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 200 lease blocks of 3-D seismic data in the Gulf
of Mexico. exploration
BALANCE SIZE AND RISK PROFILE OF EXPLORATION TARGETS. Basin conducts 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 to reduce development costs
and expedite commencement of production. This balance allows the Company to
mitigate risk while gaining exposure to meaningful growth in reserves and
production. For example, Basin drilled three discovery wells on Eugene Island
Block 49, Eugene Island Block 83 and West Cameron Block 56, respectively, during
September 1997. All three of these moderate-sized discoveries were in shallow
waters, near shore and existing infrastructure, and the Company anticipates that
all three wells will commence production by early-1998. The Company's aggregate
net investment in these three properties through September 30, 1997 was
approximately $6 million, and aggregate PV-10 Value at that date (net of all
future development and property abandonment costs) was $30 million. By contrast,
Eugene Island Block 65 was a higher-risk prospect that resulted in a
significantly larger discovery, accounting for $56.8 million of net PV-10 value
at September 30, 1997. The Company's current prospect inventory includes a broad
range of risk and reserve target sizes.
GENERATE PROSPECTS INTERNALLY. Basin's team of geoscientists internally
generates high quality 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 to swap for interests in third-party
generated prospects. For example, the Company generated a prospect on Eugene
Island Block 65, acquired a 100% interest in the prospect at a lease sale, sold
promoted interests to three partners, and currently operates the property with a
71.4% working interest, which includes certain interests re-acquired after
drilling the test well.
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.
Although the Company primarily relies on internal generating activities for
prospect leads, the Company also evaluates outside-generated opportunities. Of
the 30 Gulf of Mexico prospects that the Company has assembled to-date, 21 were
generated internally and 20 remain to be drilled. Several of the
outside-generated prospects have been obtained in conjunction with the
originating party's participation in prospects generated by the Company.
OPERATE CORE PROPERTIES. At September 30, 1997, Basin served as operator
for properties accounting for more than 80% of the Company's PV-10 Value.
Serving as operator allows the Company to exert greater control over the cost
and timing of its exploration, development and production activities.
PURSUE SELECTIVE ACQUISITIONS. Basin actively seeks to acquire working
interests in oil and gas properties with development potential to augment
operations in its core areas, to build acreage positions for exploration
prospects and to establish positions in new areas. By combining Gulf of Mexico
exploration activities with acquisition and exploitation activities in a broader
geographic area, the Company seeks to
S-31
<PAGE>
diversify risks, balance shorter-lived producing properties with longer-lived
assets, maintain a reserve base that includes significant quantities of both oil
and gas, and expose the Company to developing plays that may offer opportunities
to establish new focus areas for future activities. 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.
Basin uses advanced technologies, including 3-D seismic data and
computer-aided exploration and exploitation, to identify properties with upside
potential. Acquisition, exploration and property management strategies and
efforts are integrated to pursue acquisitions of proved properties with
identified exploration potential and to evaluate exploration potential on
existing assets. For example, the Company closed a $14.4 million acquisition in
the first quarter of 1997, which increased the Company's interests in Eugene
Island Block 65 after drilling the discovery well but before drilling the second
well, and which also included an interest in a recent discovery well on East
Cameron Block 378 and interests in three separate prospects on East Cameron
Block 378, Eugene Island Block 65 and Eugene Island Block 64. The prospect on
East Cameron Block 378 has multi-pay sand potential, and the Company anticipates
that a test well will be drilled in 1998. In addition, through this transaction
the Company acquired options on interests in two additional prospects in which
the Company expects to participate in late 1997 or in 1998. The Company's
acquisition and geotechnical teams worked jointly to evaluate the value of the
proved reserves and drilling potential for these properties.
MAINTAIN FINANCIAL FLEXIBILITY. Basin is committed to maintaining financial
flexibility in order to pursue exploration and development activities and take
advantage of selective acquisition opportunities. The Offering will enhance
Basin's financial flexibility by further strengthening its balance sheet.
SIGNIFICANT PROVED PROPERTIES AND SELECTED PROSPECTS
The Company's properties are located offshore in the shallow waters of the
Gulf of Mexico and several basins in the Rocky Mountains.
The Company's proved properties described below account for approximately
87% of the Company's PV-10 Value at September 30, 1997. Also described below are
several of the Company's exploratory drilling locations that the Company
anticipates will be tested by the end of 1998. Production test data may not
necessarily be indicative of future production rates. Although the Company has
identified prospects on these properties, there can be no assurance that such
prospects will be drilled or that drilling will establish commercial production.
OFFSHORE
PRODUCING PROPERTIES
EUGENE ISLAND BLOCK 65. Basin acquired a 100% working interest in Eugene
Island Block 65 for $6.4 million in the first Outer Continental Shelf ("OCS")
lease sale at which it participated, in April 1996. This block was one of the
most sought-after leases at the sale with 14 companies participating in eight
separate bids. It is located approximately 18 miles offshore Louisiana in 21
feet of water. Prior to the Company's acquisition, Eugene Island Block 65 had
produced marginally from two wells drilled on the block by another energy
company. Using new 3-D seismic data that became available shortly before the
lease sale, the Company identified two prospect traps with seismic amplitude
anomalies in multiple Miocene-age sands.
In the second half of 1996, the Company brought three industry partners into
the property, recouping two-thirds of the Company's total investment and
receiving a partial carried interest in the first exploratory well while
retaining a 37.5% working interest before project payout and a 47.5% working
interest after project payout. Basin is the operator of Eugene Island Block 65.
S-32
<PAGE>
The Company subsequently drilled and completed two exploratory wells on this
block. The first well encountered 111 net feet of gas/condensate pay in two
zones, and the second well intersected 145 net feet of gas/condensate pay in
three zones, below a true vertical depth of 12,500 feet. Production from both
dually-completed wells commenced in August 1997 (seven months after initial
discovery) following Basin's installation of refurbished and upgraded four-pile
platform facilities and a pipeline connecting the facilities to a gas/condensate
sales trunkline.
After drilling the discovery well in January 1997, but before spudding the
second well in February, the Company increased its working interests in Eugene
Island Block 65 to 62.5% before payout and 67.5% after payout when it acquired
the interests of a partner. At the beginning of September 1997, the Company
again increased its working interests in Eugene Island Block 65 to 71.4% before
payout and 76.4% after payout, by acquiring the interests of another partner.
During September 1997, which was the first full month of production on the
property, the Company's average daily production from Eugene Island Block 65 was
46.0 MMcf (26.7 MMcf net) of gas, and 1,474 Bbl (858 Bbl net) of condensate,
increasing the Company's overall net production for the month by approximately
273%. This gross production level represents the approximate sustainable
capacity of the installed facilities. Additional behind pipe reserves are
available for production when additional platform and pipeline capacity becomes
available. The Company has also identified a smaller separate prospect on the
block that is supported by a hydrocarbon indicator response. This prospect will
be considered for drilling at a later date when platform capacity is available.
UNDEVELOPED DISCOVERIES
The Company has four drilled discovery wells and one acquired discovery well
in the Gulf of Mexico that are currently being developed for production. All
five wells are expected to commence production in late 1997 or in 1998. Net feet
of pay and production tests described for these wells are not necessarily
indicative of future production rates or completion success. The timing of
future development of these discoveries is dependent on many factors which may
or may not be within the Company's control, such as actions of third-party
operators or equipment availability.
As of September 30, 1997, the Company had estimated net proved reserves
attributable to these five discoveries of 22.3 Bcf and 519 MBbls, or 25.4 Bcfe.
The Company has invested a total of $14.1 million on these discoveries,
resulting in an aggregate PV-10 Value at that date (net of future development
and prospect abandonment costs of $12.5 million) of $48.2 million, which
represents 32% of the Company's PV-10 Value.
EAST CAMERON BLOCK 378. Basin acquired interests in East Cameron Block 378
as part of an acquisition in February 1997 that also included interests in
Eugene Island Block 65. East Cameron Block 378 is located in 450 feet of water
approximately 110 miles offshore Louisiana. The acquisition included a 46.5%
working interest in a new discovery well. The block had no previous production,
but a discovery well drilled just prior to the Company's acquisition intersected
121 net feet of gas pay at a vertical depth of approximately 3,300 feet. The
well was completed subsea in a single zone that was flow tested at 14 MMcf of
gas per day. Production is expected to commence from this well by late 1997 or
early in the first quarter of 1998, after an umbilical line and pipeline are
installed to connect the well to a nearby third-party platform. Zilkha Energy is
the operator of the property.
Before acquiring the block, the Company purchased a 3-D seismic survey to
evaluate the proved reserves and to prospect for additional upside potential. A
separate prospect trap with multiple seismic amplitude anomalies has been
identified on the block, which is expected to be tested in 1998. The Company
acquired a 23.25% working interest in the prospect, with the seller retaining
one-half of its original interest.
S-33
<PAGE>
EUGENE ISLAND BLOCK 49. This Basin-operated block is located 20 miles
offshore Louisiana in 20 feet of water. Basin acquired 100% of this lease at the
March 1997 OCS lease sale for $667,000. Another energy company drilled a well on
this block in 1992 that encountered gas pay in three zones below 7,300 feet true
vertical depth. Utilizing new 3-D seismic data and conventional well log
analysis, the Company identified a prospect with multiple sand objectives that
are correlative to this abandoned well in an improved structural location and
two separate modest-sized prospects on the block.
The primary prospect tested was in the upper Miocene Rob E sand in an
upthrown fault closure on a down-to-the-southeast fault. In the third quarter of
1997, the Company drilled this prospect, in which it owns a 100% working
interest, and commenced completion operations after intersecting 63 net feet of
gas/ condensate pay in several zones below 7,300 feet true vertical depth.
Production is expected to commence from the well shortly before or during the
first quarter of 1998 after the Company installs minimal production facilities
and a pipeline to connect to a nearby gas/condensate sales trunkline or to a
nearby third-party platform.
EUGENE ISLAND BLOCK 83. This Basin-operated block is located 15 miles
offshore Louisiana in 25 feet of water. The Company acquired a 60% working
interest in this block at an OCS lease sale in March 1997 for $667,000 net.
Prior to the Company's acquisition, Eugene Island Block 83 had no previous
production, although four prior unsuccessful exploration wells had been drilled
on this block by other energy companies. One such well encountered hydrocarbons
that were considered non-commercial. Before acquiring the lease block, the
Company purchased a 3-D seismic survey and identified a prospect trap with
seismic amplitude anomalies in multiple Miocene-age sands.
In the third quarter of 1997, the Company drilled and completed an
exploratory well on the block. The well intersected approximately 100 net feet
of gas/condensate pay in several zones below a true vertical depth of 11,200
feet and was tested at gross rates up to 15 MMcf of gas per day and 379 Bbl of
condensate per day. However, the Company anticipates bringing the well on-line
at lower rates than tested. Production is expected to commence from the well
shortly before or during the first quarter of 1998 after the Company installs a
caisson platform and pipeline connecting the facility to a gas sales trunkline.
WEST CAMERON BLOCK 56 NE/4. This Basin-operated block is located eight
miles offshore Louisiana in 35 feet of water. The Company acquired a 100%
working interest in certain intervals under the northeast quarter of this block
by farming in interests from two companies. The Company subsequently brought an
industry partner into the block on terms providing for the partner to pay 44.4%
of total costs incurred through the first exploratory well for a 33.3% working
interest. The Company retained a 66.7% working interest.
Prior to the Company's acquisition, 25 wells had been drilled on West
Cameron Block 56. West Cameron 56 NE/4 is part of a producing field complex that
extends into Block 45 to the north and which has cumulative production in excess
of 325 Bcf of gas and 11 MMBbl of oil and condensate from multiple Miocene-age
sands. Before acquiring the block, the Company purchased a 3-D seismic survey
and identified an undrilled structural fault block with a seismic amplitude
anomaly.
In the third quarter of 1997, Basin drilled an exploratory well on the
prospect. This well intersected 86 net feet of gas/condensate pay in a
geopressured sand below a true vertical depth of 9,900 feet and has been
completed and tested at gross rates up to 10 MMcf of gas per day and 440 Bbl of
condensate per day. Basin expects to commence production from this well shortly
before or during the first quarter of 1998, after the Company installs a caisson
platform and pipeline connecting the facility to either a gas/ condensate sales
trunkline or a nearby third-party platform.
S-34
<PAGE>
WEST DELTA BLOCK 122. This Vastar Resources-operated block is located on
the north flank of a piercement salt dome situated approximately 28 miles
offshore Louisiana in 270 feet of water. The Company acquired a 25% working
interest in West Delta Block 122 from a major oil company in 1997. Between 1967
and 1969, an earlier lessee of Block 122 produced less than one million barrels
of oil and approximately one Bcf of gas from two wells on this block. The
Company identified its initial prospects on this block using 2-D seismic data
and purchased a 1996 vintage 3-D seismic survey prior to acquiring an interest
in the block.
In the third quarter of 1997, the Company participated in a successful
exploratory well on West Delta Block 122. The No. 1 well encountered in excess
of 150 net feet of oil and gas pay in several Pleistocene/ Upper Pliocene-age
sands. Production casing has been set in the No. 1 well and the well has been
temporarily suspended. A second well was spudded on the block in September 1997
to test a separate prospect, and was drilling as of September 30, 1997. Further
development plans for West Delta 122, potentially including proposals for
additional wells, will not be formulated until after results are obtained from
the No. 2 well, and first production from the property is not anticipated before
the second half of 1998.
EXPLORATORY PROSPECTS--1997 AND 1998 DRILLING PROGRAM
During the first nine months of 1997, the Company successfully drilled six
of eight exploratory wells in the Gulf of Mexico. During this period, the
Company drilled prospects that could be expeditiously completed and brought into
production prior to the winter heating season. Two of these wells began
production in August 1997, and three of these wells will commence production by
early-1998.
The Company currently has an inventory of 20 prospects in the Gulf of
Mexico. The Company intends to drill 12 to 15 exploratory wells through 1998 on
its current prospect inventory or on selected new prospects that may be
assembled. Described below are eight exploratory prospects that represent the
Company's highest cost and, in the Company's estimation, highest potential
prospects, which Basin expects to drill through 1998. In addition, the Company
has options to acquire interests in other exploratory prospects of similar size
and risk potential, which the Company currently intends to drill during 1998 if
the outside operator elects to conduct drilling operations. No assurance can be
given that these prospects will be drilled in 1998 or afterward, since drilling
plans are affected by many factors which may or may not be in the Company's
control, such as success in finding drilling partners, equipment availability,
actions of third-party operators, or availability of other opportunities for
Company investment.
EAST CAMERON BLOCK 378. This Zilkha Energy-operated block is located 110
miles offshore Louisiana in 450 feet of water. The Company acquired a 23.25%
interest in the exploratory rights on this block in February 1997 as a part of
an acquisition that also included a 46.5% interest in a discovery well drilled
on the block in January 1997, which is currently awaiting connection to a nearby
platform. The exploratory prospect targets geopressured Pleistocene-aged sands
that exhibit several stacked amplitude anomalies below approximately 11,000 feet
vertical depth on the north flank of a piercement salt dome. The Company is
participating with the operator in reprocessing the 3-D seismic data across the
block utilizing pre-stack time migration in order to improve the imaging of the
salt-sediment interface. Pending the results of the seismic reprocessing, a test
well is tentatively planned in 1998.
EAST CAMERON BLOCK 34, #1 AND #2. This Basin-operated block is located 7
miles offshore Louisiana in 37 feet of water. The Company acquired a 60%
interest in the lease at the March 1997 OCS sale for a net $1.3 million. The
principal targets on this block are two separate structural traps in the
lower-Miocene Rob L Sands. One of the prospects is an upthrown three-way closure
with a hydrocarbon indicator response, or bright spot. This upthrown fault
system is productive in two separate closures adjacent to the prospect.
Additional potential at this location exists at a deeper Rob L horizon which
also produces on nearby upthrown closures. The second prospect on the block is
similar in character and also exhibits a good
S-35
<PAGE>
hydrocarbon indicator response in multiple Rob L sands. Both prospects on this
block are expected to be drilled in late 1997 or in 1998, with planned drilling
depths to approximately 11,500 feet.
SHIP SHOAL BLOCK 103. This Basin-operated block is located 25 miles
offshore Louisiana in 37 feet of water. The Company acquired 100% of the lease
at the March 1997 OCS sale for $611,000. This prospect targets geopressured
Miocene-aged sands at a true vertical depth of approximately 14,500 feet in an
upthrown trap on a down-to-the-east fault that is part of the same system that
traps a producing field at Ship Shoal Block 100 approximately eight miles to the
east. A strong bright spot is evident on new 3-D seismic data, analogous to ones
seen at the Ship Shoal 100 Field. The Company intends to bring in a partner on a
promoted basis or in exchange for an interest in another prospect and expects to
test the prospect in 1998.
VERMILION BLOCK 16. This Basin-operated block is located three miles
offshore Louisiana in 25 feet of water. The Company acquired a 60% interest in
the lease at the March 1997 OCS sale for $334,000 net. It is an 800-acre federal
lease bordering Louisiana state waters. This prospect is located in the prolific
lower Miocene Rob M trend that has produced in excess of 2.7 Tcfe from the same
age sands about three miles southeast at Vermilion 25/26 Field. This prospect,
which covers a much smaller area than the Vermilion 25/26 Field, is a three-way
structural closure that is down-thrown to a large growth fault. There are no
hydrocarbon indicators associated with this prospect, but structurally the
prospect is syncline separated from and at the same approximate depth as the
Vermilion 25/26 Field and is also syncline separated from the Vermilion 24 Field
which produced from deeper Rob M sands. This prospect straddles a lease line and
resides on both Vermilion Block 16 and Block 25, which was acquired at the same
lease sale by another energy company submitting a higher bid than the Company.
Since the prospect is on portions of both leases, the Company anticipates that a
test well will most likely be drilled on a joint basis, pending the negotiation
of an equitable split of prospect ownership between owners of both blocks.
Therefore, an exact determination of the Company's position in the prospect
cannot be made at this time, nor can the timing of a test well be established.
The anticipated target well depth is approximately 16,000 feet.
VERMILION BLOCK 267 N/2. This Basin-operated half-block is located 70 miles
offshore Louisiana in 160 feet of water. The Company acquired a 40% working
interest in this lease at the March 1997 OCS sale for $353,000 net. This
prospect targets normal-pressured Pliocene age sands at 11,300 feet which
exhibit good amplitude anomalies with strong hydrocarbon indicators that are
offsetting an adjacent producing field with cumulative production of 85 Bcfe.
The Company anticipates drilling a test well to a true vertical depth of
approximately 12,800 feet in 1998 to evaluate this prospect.
VERMILION BLOCK 368. This IP Petroleum-operated block is located 105 miles
offshore Louisiana in 320 feet of water. The Company acquired a 15% working
interest in this lease at the April 1997 OCS sale for approximately $464,000,
net. The prospect targets Pleistocene-aged sands which exhibit very strong
stacked amplitude anomalies. The feature, if productive, would require several
wells to fully develop. The Company anticipates that the operator will propose
that a test well be drilled to a true vertical depth of approximately 16,000
feet in 1998 to evaluate this prospect. The Company currently is reprocessing
the 3-D seismic data across this block utilizing pre-stack time migration in an
effort to better image the prospect.
WEST CAMERON 72. This Basin-operated block is located 12 miles offshore
Louisiana in 39 feet of water. The Company acquired 100% of the lease at the
April 1996 OCS sale for $405,000. This prospect is located in the prolific lower
Miocene Marg A trend on the west flank of the West Cameron Block 71 anticline,
which has produced in excess of one Tcfe from the same age sands. This prospect
is a three-way structural closure at a true vertical depth of approximately
14,000 feet that is upthrown to a down-to-the-south fault that traps reserves on
the West Cameron Block 71 complex. The Company currently is reprocessing the 3-D
seismic data on a prospect specific basis to include pre-stack
amplitude-versus-offset analysis. The Company intends to bring in a partner on a
promoted basis or in exchange for an interest in another prospect prior to
drilling a test well.
S-36
<PAGE>
ONSHORE
PRODUCING PROPERTIES
SCOTT FIELD. The Company established its interests in the Scott Field
primarily through two acquisitions closed in 1993 and 1994. It is a mature oil
field located in the southern end of the Powder River Basin, and cumulative
production from the field exceeds 15 MMBbl of oil and 19 Bcf of gas from
approximately 215 wells. The Company currently operates 98 wells in the field
and has non-operated interests in 14 wells. As of September 30, 1997, the
Company had 19 remaining proved undeveloped drilling locations in the Scott
Field, with estimated future net development costs of $5.4 million. The
Company's net production from the field averaged approximately 660 Bbl and 730
Mcf, or 4,700 Mcfe, per day during September 1997.
JEPSON-HOLLER DRAW SHANNON SANDSTONE UNIT. The Jepson-Holler Draw Shannon
Sandstone Unit (the "Unit") is located in the southwestern portion of the Powder
River Basin. The Unit was formed effective April 1, 1996 for the purpose of
secondary recovery through water injection. The Company owns a 26.7% working
interest in the Unit, most of which was obtained in a September 1996
acquisition. Ensign Oil and Gas is the operator of the Unit.
Waterflood installation was initiated during the summer of 1996 and as of
July 1997, 33 wells had been converted from producer to injector. Phase II
development, which consists of drilling 24 infill producing wells and building
centralized production facilities, is expected to commence after waterflood
response is observed in the existing producers, which the Company has projected
for early 1999. The Unit does not currently generate significant production and
is not projected to do so until development enters Phase II.
OIL AND GAS RESERVES
The Company engaged Ryder Scott, independent petroleum engineers, to prepare
estimates of total proved reserves, projected future production, and estimated
future net revenues from production of proved reserves for the Company's
offshore properties as of September 30, 1997 and December 31, 1996. Basin
engaged Netherland Sewell to audit the Company's estimates for its onshore
properties as of such dates. 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 September 30, 1997 and December 31, 1996 were utilized.
The following table sets forth estimates as of September 30, 1997 and
December 31, 1996 derived from the Company's reserve reports. The PV-10 Values
shown in the table are not intended to represent the current market value of the
estimated oil and gas reserves owned by the Company. See "Risk Factors--
Estimates of Reserves and Related Data." 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>
AS OF SEPTEMBER 30, 1997 AS OF DECEMBER 31, 1996
------------------------------------ ------------------------------------
DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL
---------- ------------ ---------- ----------- ------------ ---------
<S> <C> <C> <C> <C> <C> <C>
Oil (MBbls)........................... 4,399 3,911 8,310 4,046 3,824 7,870
Gas (MMcf)............................ 40,343 19,925 60,268 19,182 10,531 29,713
Total (MMcfe)......................... 66,737 43,391 110,128 43,458 33,475 76,933
PV-10 Value (in thousands)............ $ 106,351 $ 44,723 $ 151,074 $ 50,856 $ 32,800 $ 83,656
</TABLE>
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<PAGE>
The following table sets forth estimates relating to the Company's net
proved reserves at September 30, 1997 and December 31, 1996, by geographic area
of operation:
<TABLE>
<CAPTION>
AS OF SEPTEMBER 30, 1997 AS OF DECEMBER 31, 1996
------------------------------------------------ --------------------------------------------------
PV-10 VALUE PV-10 VALUE
GAS TOTAL (IN GAS TOTAL (IN
GEOGRAPHIC REGION OIL (MBBLS) (MMCF) (MMCFE) THOUSANDS) OIL (MBBLS) (MMCF) (MMCFE) THOUSANDS)
- --------------------------- ----------- --------- --------- ------------- ----------- --------- ----------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Offshore Gulf of Mexico.... 858 41,422 46,570 $ 105,072 49 6,391 6,685 $ 16,286
Powder River Basin......... 6,454 8,619 47,343 35,423 6,697 10,737 50,919 48,138
Greater Green River
Basin..................... 364 7,251 9,435 5,572 380 8,372 10,652 11,746
Other Onshore.............. 634 2,976 6,780 5,007 744 4,213 8,677 7,486
----- --------- --------- ------------- ----- --------- ----------- -------------
Total.................... 8,310 60,268 110,128 $ 151,074 7,870 29,713 76,933 $ 83,656
----- --------- --------- ------------- ----- --------- ----------- -------------
----- --------- --------- ------------- ----- --------- ----------- -------------
</TABLE>
Future cash flows attributable to the Company's historical estimated net
proved reserves were based on an average gas price of $2.80 per Mcf and an
average oil price of $20.08 per Bbl at September 30, 1997 and an average gas
price of $3.02 per Mcf and an average oil price of $25.35 per Bbl at December
31, 1996.
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, PV-10 Values 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 the Company's reserves.
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<PAGE>
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 September 30, 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............................................ 500 357 90,141 61,353
Texas offshore................................................ -- -- 720 270
--------- --------- --------- ---------
Total offshore.............................................. 500 357 90,861 61,623
--------- --------- --------- ---------
Wyoming....................................................... 44,899 26,311 69,648 47,959
Utah.......................................................... 1,762 984 13,713 7,350
Montana....................................................... -- -- 11,175 7,628
Other onshore................................................. 2,227 960 7,887 4,398
--------- --------- --------- ---------
Total onshore............................................... 48,888 28,255 102,423 67,335
--------- --------- --------- ---------
Total..................................................... 49,388 28,612 193,284 128,958
--------- --------- --------- ---------
--------- --------- --------- ---------
</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 above presentation.
PRODUCTION
The following table sets forth Basin's net oil and gas production, average
net daily oil and gas production, average sales prices and costs and expenses
associated with such production during the periods indicated.
<TABLE>
<CAPTION>
THREE MONTHS ENDED
NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30, YEAR ENDED DECEMBER 31,
-------------------- ---------------------- -------------------------------
1997(1) 1996 1997(1)(2) 1996 1996(2) 1995 1994
--------- --------- ----------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
Net production:
Oil (MBbls)......................... 147 98 356 466 564 1,153 1,278
Gas (MMcf).......................... 1,688 429 2,490 4,353 4,776 12,833 14,377
Total (MMcfe)....................... 2,570 1,017 4,626 7,149 8,160 19,751 22,045
Average net daily production:
Oil (Bbls).......................... 1,600 1,064 1,304 1,699 1,540 3,160 3,501
Gas (Mcf)........................... 18,353 4,664 9,121 15,886 13,050 35,154 39,389
Total (Mcfe)........................ 27,953 11,048 16,945 26,080 22,290 54,114 60,395
Average sales price per unit (3):
Oil (per Bbl)....................... $ 18.59 $ 21.10 $ 18.88 $ 19.55 $ 20.03 $ 17.02 $ 15.63
Gas (per Mcf)....................... $ 2.45 $ 1.22 $ 2.37 $ 1.39 $ 1.44 $ 1.56 $ 1.69
Total (per Mcfe).................... $ 2.67 $ 2.54 $ 2.73 $ 2.12 $ 2.23 $ 2.01 $ 2.01
Production cost per Mcfe (4).......... $ 0.50 $ 1.08 $ 0.86 $ 0.74 $ 0.81 $ 0.59 $ 0.55
</TABLE>
- ------------------------
(1) For the month of September 1997, which included the first full month of
production from the Company's Eugene Island Block 65 property, Basin's net
production totaled 1,307 MMcfe, average
S-39
<PAGE>
net daily production totaled 43,573 Mcfe, average sales price per unit
totaled $2.71 per Mcfe and production cost per Mcfe totaled $0.31.
(2) Production decreased from 1995 to 1996 and from the first nine months of
1996 to the first nine months of 1997 as a result of the D-J Sales
consummated in the first half of 1996. As of December 31, 1995, the D-J
Basin assets represented approximately two-thirds of the Company's producing
wells and 70% of its proved oil and gas reserves. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations--Results of Operations."
(3) Includes the effects of the Company's hedging activities. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
(4) Includes direct lifting costs (labor, repairs and maintenance, materials and
supplies) and the administrative costs of production offices, insurance and
property and severance taxes.
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>
YEARS ENDED DECEMBER 31,
NINE MONTHS ENDED -------------------------------
SEPTEMBER 30, 1997 1996 1995 1994
------------------ --------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Development costs................................. $ 5,989 $ 4,472 $ 7,427 $ 42,113
Exploration costs................................. 21,026 10,250 2,003 2,361
Leasehold and acquisition costs:
Unproved properties............................. 6,119 5,056 2,429 5,275
Proved properties............................... 19,157 3,067 3,889 16,751
------- --------- --------- ---------
Total costs incurred.............................. $ 52,291 $ 22,845 $ 15,748 $ 66,500
------- --------- --------- ---------
------- --------- --------- ---------
</TABLE>
S-40
<PAGE>
MANAGEMENT
DIRECTORS AND EXECUTIVE OFFICERS
The following table sets forth the names, ages and titles of the officers
and members of the Board of Directors of the Company:
<TABLE>
<CAPTION>
NAME AGE POSITION
- ------------------------------------ --- ---------------------------------------------------------------------
<S> <C> <C>
Michael S. Smith(1)................. 42 Chairman of the Board, President and Chief Executive Officer
Neil L. Stenbuck(1)................. 44 Vice President--Finance, Chief Financial Officer, Treasurer and
Director
Howard L. Boigon(1)................. 50 Vice President--General Counsel, Secretary and Director
Thomas J. Corley.................... 37 Vice President--Engineering and Production
Dalton F. Polasek, Jr............... 45 Vice President--Gulf Coast Engineering
David A. Pustka..................... 43 Vice President--Gulf Coast Exploration
Sam D. Winegrad..................... 38 Vice President--Corporate Development
John F. Greene(2)................... 57 Director
J. Paul Hellstrom(2)(3)............. 56 Director
Michael A. Nicolais(2)(3)........... 70 Director
Larry D. Unruh(2)(3)................ 46 Director
</TABLE>
- ------------------------
(1) Member of the Executive Committee.
(2) Member of the Compensation and Incentive Committee.
(3) Member of the Audit Committee.
MICHAEL S. SMITH is Chairman of the Board, President, Chief Executive
Officer, a director and a founder of the Company. Mr. Smith has been Chairman of
the Board since 1983 and has been a director since inception. Mr. Smith was
elected President and Chief Executive Officer in 1988. Mr. Smith is past
president and a director of the Colorado Oil and Gas Association and served on
the State of Colorado Governor's Minerals, Energy & Geology Policy Advisory
Board.
NEIL L. STENBUCK is Vice President--Finance, Chief Financial Officer,
Treasurer and a director of the Company. He joined the Company in 1995. He was
previously with United Meridian Corporation ("UMC") where he served as vice
president--capital as a result of the 1994 merger between UMC and General
Atlantic Resources, Inc. ("GA Resources"), where he occupied the same position
since 1989. He joined GA Resources in 1987 as vice president--finance and
accounting.
HOWARD L. BOIGON is Vice President--General Counsel, Secretary and a
director of the Company. Mr. Boigon joined the Company in March 1992.
Previously, he had been a partner in the Denver office of Davis, Graham & Stubbs
since 1978, having been with the firm since 1973 specializing in the practice of
oil and gas law. Mr. Boigon began representing the Company as outside counsel in
1989. He is currently president of the Colorado Oil and Gas Association and is a
member of the Advisory Board of the International Oil and Gas Educational Center
of the Southwestern Legal Foundation. He has served as Chair of the Mineral Law
Section of the Colorado Bar Association, and Trustee of the Rocky Mountain
Mineral Law Foundation. He has lectured and written on various topics of oil and
gas law.
THOMAS J. CORLEY is Vice President--Engineering and Production of the
Company. He joined the Company in March 1996. For the previous three years he
was vice president--engineering at St. Mary Land & Exploration Company where he
was responsible for the acquisition efforts and engineering functions of the
company. From 1983 to 1993 he held various positions at GA Resources, most
recently as director of acquisitions. Mr. Corley is a member of the Society of
Petroleum Engineers and served as a distinguished panel member at the 1995 SPE
Annual Meeting.
S-41
<PAGE>
DALTON F. POLASEK, JR. is Vice President--Gulf Coast Engineering of the
Company. Mr. Polasek has been employed in that position since February 1996.
From 1994 to 1996, he was employed by SMR Energy Income Funds, as Vice President
of Engineering. From 1991 to 1994, Mr. Polasek served as the Director of Gulf
Coast Acquisitions/Engineering for GA Resources. Prior to joining GA Resources,
Mr. Polasek served as manager of planning and business development for Mark
Producing Company from 1983 to 1991.
DAVID A. PUSTKA is Vice President--Gulf Coast Exploration and Gulf Coast
Division Manager of the Company. He joined the Company in November 1995. From
1992 to 1995 he was vice president in charge of United States exploration for
British-Borneo Exploration, Inc., a wholly-owned subsidiary of British-Borneo
Petroleum Syndicate, PLC. From 1983 to 1992, he was responsible for exploration
activities at Walter Oil & Gas Corporation, a privately held Gulf of Mexico
exploration company, becoming a vice president in 1990. Mr. Pustka is a member
of the American Association of Petroleum Geologists and the Houston Geological
Society.
SAM D. WINEGRAD is Vice President--Corporate Development of the Company. He
joined the Company in August 1995. Mr. Winegrad was previously with UMC where he
was vice president--land, the same position he occupied at GA Resources at the
time of its merger in 1994 with UMC. He joined GA Resources in 1985 and became
vice president--land in 1987.
JOHN F. GREENE is a director of the Company. He was elected to that position
in February 1996. From 1985 until his retirement in 1995, he served as executive
vice president of exploration and production for the Louisiana Land and
Exploration Company, where he served on the board of directors from 1989 until
his retirement. From 1981 to 1985, Mr. Greene was president and chief executive
officer for Milestone Petroleum and then executive vice president of exploration
for Meridian Oil and Gas Company via its merger with Milestone. He began his
career at Continental Oil Company holding various positions including director
of exploratory projects for onshore and offshore offices and a division
exploration manager for the western United States.
J. PAUL HELLSTROM is a director of the Company. He was elected to that
position in March 1992. Mr. Hellstrom was employed by The First Boston
Corporation from 1975 to 1989. At the time of his retirement in 1989, Mr.
Hellstrom was co-head of First Boston's Real Estate Group, earlier having served
as head of its Energy and Project Finance Groups. Prior to joining First Boston,
he was a first vice president in charge of the Project Finance Group at Blyth
Eastman Dillon & Co., Inc. and an assistant treasurer with Manufacturers Hanover
Trust Company. Mr. Hellstrom currently serves as a director of First Reserve
Corporation. First Reserve is a direct investor in natural resource and
energy-related industries.
MICHAEL A. NICOLAIS is a director of the Company. He was elected to that
position in March 1992. Since April 1993 he has been employed by Carret & Co.,
Inc. From June 1991 to April 1993, he was employed by Goldman Capital
Management, Inc. From 1949 to 1991, Mr. Nicolais was employed by The Clark
Estates, Inc., serving as president from 1968 to 1990. During 10 years of his
tenure, Mr. Nicolais made oil and gas investments on behalf of The Clark
Estates, Inc. Most of these investments were consolidated into a corporation
that merged with International Oil and Gas Company and were subsequently sold to
Depco Petroleum and Husky Oil. As a result of his position with The Clark
Estates, Inc., he has served as a director of several energy and natural
resource companies. In the mid- to late-1960s, Mr. Nicolais was president of
Hugoton Production Company, a gas company with over a trillion cubic feet of
reserves in southwestern Kansas. Hugoton Production Company merged into Mesa
Petroleum Company in 1969. Mr. Nicolais served as a director of Mesa Petroleum
Company from 1969 until 1984. He serves as a director of Southdown, Inc. and
Hitox Corp. of America.
LARRY D. UNRUH is a director of the Company. He was elected to that position
in March 1992. Since 1982 he has been the managing tax partner at Hein +
Associates, certified public accountants. During 1980 and 1981 he was chief
financial officer of Otis Energy Inc. Prior to 1980, Mr. Unruh held tax and
accounting
S-42
<PAGE>
positions with Hein + Associates, Coopers & Lybrand, and Peat Marwick Mitchell &
Co. Mr. Unruh is a Certified Public Accountant and is a member of the Federal
Tax Division of American Institute of Certified Public Accountants. Hein +
Associates previously served as the Company's auditing firm and continues to
provide tax advisory services to the Company. Mr. Unruh serves as a director of
Alpharel Inc., an electronic imaging company.
All directors of the Company serve staggered terms of three-years and hold
office until the annual meeting in the year in which their respective terms
expire or until their respective successors are duly elected and qualified. The
terms of Messrs. Smith, Nicolais and Unruh are scheduled to expire in 1998; the
terms of Messrs. Greene and Stenbuck are scheduled to expire in 1999 and the
terms of Messrs. Boigon and Hellstrom are scheduled to expire in 2000. All
officers of the Company serve at the discretion of the Board of Directors. There
are no family relationships between any director, officer or person nominated or
chosen to become a director of officer and any other such persons.
S-43
<PAGE>
SELLING STOCKHOLDER
The following table sets forth certain information regarding the beneficial
ownership of the Common Stock as of September 30, 1997, and as adjusted to
reflect the Offering, of the Selling Stockholder:
<TABLE>
<CAPTION>
SHARES BENEFICIALLY SHARES BENEFICIALLY
OWNED PRIOR TO THE OWNED AFTER THE
OFFERING NUMBER OF SHARES TO OFFERING
----------------------- BE SOLD IN THE -----------------------
SELLING STOCKHOLDER NUMBER PERCENT OFFERING NUMBER PERCENT
- ------------------------------------------- ---------- ----------- --------------------- ---------- -----------
<S> <C> <C> <C> <C> <C>
Michael S. Smith........................... 3,248,150(1) 30.1 200,000 3,048,150 22.9
</TABLE>
- ------------------------
(1) Includes 2,675,150 shares held by Mr. Smith; 304,300 shares held by Iris
Smith, Mr. Smith's wife; 96,000 shares held by trusts for Mr. Smith's
children, of which Mr. Smith is trustee; and 92,700 shares held by KaiTar
Foundation, a nonprofit charitable foundation of which Mrs. Smith is
president and Mr. Smith is vice-president. Mr. Smith has no voting or
investment power with respect to the shares held by Iris Smith and disclaims
beneficial ownership of such shares. Mr. Smith, in his capacity as the
trustee of the trusts for his children and as vice president of KaiTar
Foundation, has voting and investment power with respect to the shares held
in such capacity and may be deemed to be the beneficial owner of such shares
but disclaims beneficial ownership of such shares. Also includes options for
60,000 shares exercisable within 60 days and 20,000 performance shares, the
restrictions on which lapse December 31, 1999.
S-44
<PAGE>
UNDERWRITING
The Underwriters named below (the "Underwriters") have severally agreed,
subject to the terms and conditions of the Underwriting Agreement, to purchase
2,500,000 shares of Common Stock from the Company and 200,000 shares of Common
Stock from the Selling Stockholder. The aggregate number of shares of Common
Stock each Underwriter has agreed to purchase is set forth opposite their names
below:
<TABLE>
<CAPTION>
NUMBER OF
UNDERWRITER SHARES
- --------------------------------------------------------------------------------- ----------
<S> <C>
Morgan Keegan & Company, Inc.....................................................
Howard, Weil, Labouisse, Friedrichs Incorporated.................................
Petrie Parkman & Co., Inc........................................................
Rauscher Pierce Refsnes, Inc.....................................................
----------
Total...................................................................... 2,700,000
----------
----------
</TABLE>
Under the terms and conditions of the Underwriting Agreement, the
underwriters are committed to take and pay for all of the shares of Common Stock
(other than shares of Common Stock covered by the over-allotment options), if
any are taken.
The Underwriters propose to offer the shares of Common Stock in part
directly to the public at the initial public offering price set forth on the
cover page of this Prospectus, and in part to certain securities dealers at such
price less a concession of $ per share. The Underwriters may allow, and such
dealers may allow, a concession not in excess of $ per share to certain
brokers and dealers. After the shares of Common Stock are released for sale to
the public, the offering price and other selling terms may from time to time be
varied by the Underwriters.
The Company and the Selling Stockholder have granted the Underwriters
options exercisable for 30 days after the date of this Prospectus Supplement to
purchase up to 375,000 and 30,000 shares of Common Stock, respectively, for an
aggregate of 405,000 additional shares of Common Stock solely to cover over-
allotments, if any. If the Underwriters exercise their over-allotment options,
the Underwriters have severally agreed, subject to certain conditions, to
purchase approximately the same percentage thereof that the number of shares of
Common Stock to be purchased by each of them, as shown in the table above, bears
to the 405,000 shares of Common Stock.
The Company and the Selling Stockholder have agreed in the Underwriting
Agreement not to offer, sell, contract to sell, grant any option to purchase or
otherwise dispose of any shares of Common Stock or any securities convertible
into or exercisable or exchangeable for Common Stock, subject to certain limited
exceptions, for a period of 90 days after the date of this Prospectus Supplement
without the prior written consent of the Underwriters. In addition, the
Company's directors and executive officers have agreed not to sell, contract to
sell, grant any option to purchase or otherwise dispose of any shares of Common
Stock or any securities convertible into or exercisable or exchangeable for
Common Stock, other than as gifts, pledges and certain other transfers to
persons who agree to the same restrictions for a period of 90 days after the
date of this Prospectus Supplement without the prior written consent of the
Underwriters. This restriction on the Company does not apply to shares issued
upon exercise of stock options and currently outstanding warrants.
In connection with the Offering, certain Underwriters may engage in passive
market marking transactions in the Common Stock on the Nasdaq National Market
immediately prior to the commencement of sales in this offering, in accordance
with Rule 103 of Regulation M of the Exchange Act. Passive market making
consists of, among other things, displaying bids on the Nasdaq National Market
limited by the bid prices of independent market makers and purchases limited by
such prices and effected in response to order flow. Net purchases by a passive
market maker on each day are limited to a specified percentage of the passive
market maker's average daily trading volume in the Common Stock during a
specified prior
S-45
<PAGE>
period, and all passive market making activity must be discontinued when such
limit is reached. Passive market making may stabilize the market price of the
Common Stock at a level above that which might otherwise prevail, and if
commenced, may be discontinued at any time.
During and after the Offering, the Underwriters may purchase and sell shares
of Common Stock in the open market. These transactions may include
over-allotment and stabilizing transactions and purchases to cover syndicate
short positions created in connection with the Offering. The Underwriters may
also impose a penalty bid, whereby selling concessions allowed to syndicate
members or other broker-dealers for the shares of Common Stock sold in the
Offering for their account may be reclaimed by the syndicate if such shares of
Common Stock are repurchased by the syndicate in stabilizing or covering
transactions. These activities may stabilize, maintain or otherwise affect the
market price of the Common Stock, which may be higher than the price that might
otherwise prevail in the open market, and, if commenced, may be discontinued at
any time.
The Company and the Selling Stockholder have agreed to indemnify the several
Underwriters against certain liabilities, including liabilities under the
Securities Act or to contribute to payments the Underwriters may be required to
make in respect of such liabilities.
Petrie Parkman & Co., Inc. ("Petrie Parkman") and Principals of Petrie
Parkman hold warrants to purchase 51,745 shares and 40,171 shares, respectively,
of Common Stock, with an exercise price of $14 per share and a December 31, 1999
expiration date. Such warrants were acquired in the Company's merger with
Sterling Energy Corporation in November 1994. The warrants include "piggy-back"
registration rights, which were waived with respect to the Offering.
EXPERTS
The consolidated financial statements of the Company for the three years
ended December 31, 1996 included in this Prospectus Supplement have been audited
by Arthur Andersen LLP, independent public accountants, as indicated in their
report with respect thereto, and are included herein in reliance upon the
authority of said firm as experts in giving said report.
Estimates of historical onshore oil and natural gas reserves of the Company
as of September 30, 1997 and December 31, 1996 are based upon engineering
studies prepared by the Company and audited by the independent engineering firm
of Netherland Sewell. Estimates of historical offshore reserves of the Company
as of September 30, 1997 and December 31, 1996 are based upon engineering
studies prepared by the independent engineering firm of Ryder Scott. Such
estimates are included in reliance upon the authority of such firms as experts
in such matters.
LEGAL MATTERS
The validity of the shares of Common Stock have been passed upon for the
Company by Davis, Graham & Stubbs LLP, Denver, Colorado. Certain legal matters
will be passed upon for the Underwriters by Butler & Binion, L.L.P., Houston,
Texas.
S-46
<PAGE>
GLOSSARY
The terms defined in this section are used throughout this Prospectus
Summary.
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.
BTU. British thermal unit.
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.
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.
FINDING COSTS. Expressed in dollars per Mcfe, the quotient obtained by
dividing the total capital costs incurred for specified oil and gas
activities by the amount of net proved reserves added through such
activities during the same period.
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.
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 six Mcf of
gas.
MMBBL. One million barrels of crude oil or other liquid hydrocarbons.
MMBTU. One million Btus.
MMCF. One million cubic feet.
MMCFE. One million cubic feet (of gas) equivalent.
NET ACRES OR NET WELLS. The sum of the fractional working interests
owned in gross acres or gross wells.
PROVED DEVELOPED RESERVES. Reserves that can be expected to be
recovered through existing wells with existing equipment and operating
methods.
S-47
<PAGE>
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 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.
PV-10 VALUE The pre-tax, present value, discounted at 10%, of future
net cash flows from estimated net proved reserves, calculated using
unescalated prices and costs in effect on the date of the applicable reserve
reports (unless such prices or costs are subject to change pursuant to
contractual provisions).
TCFE. One trillion cubic feet (of gas) equivalent.
S-48
<PAGE>
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
---------
<S> <C>
INTERIM CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED):
Consolidated Statements of Operations for the three and nine months ended
September 30, 1997 and 1996.............................................................................. F-1
Consolidated Balance Sheets as of September 30, 1997 and December 31, 1996................................. F-2
Consolidated Statements of Cash Flow for the nine months ended
September 30, 1997 and 1996.............................................................................. F-3
Consolidated Statements of Changes in Stockholders' Equity for the year ended
December 31, 1996 and the nine months ended September 30, 1997........................................... F-4
Note to Consolidated Financial Statements.................................................................. F-5
AUDITED CONSOLIDATED FINANCIAL STATEMENTS:
Report of Independent Public Accountants................................................................... F-6
Consolidated Statements of Operations for the years ended
December 31, 1996, 1995, and 1994........................................................................ F-7
Consolidated Balance Sheets as of December 31, 1996 and 1995............................................... F-8
Consolidated Statements of Cash Flow for the years
ended December 31, 1996, 1995 and 1994................................................................... F-9
Consolidated Statements of Changes in Stockholders' Equity
for the years ended December 31, 1996, 1995 and 1994..................................................... F-10
Notes to Consolidated Financial Statements................................................................. F-11
</TABLE>
S-49
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
FOR THE THREE MONTHS FOR THE NINE
ENDED MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------- --------------------
1997 1996 1997 1996
--------- --------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
Revenue:
Oil sales........................................................... $ 2,737 $ 2,064 $ 6,720 $ 9,103
Gas sales........................................................... 4,139 522 5,910 6,065
Gain on sale of assets.............................................. -- -- -- 22,472
Interest and other.................................................. 30 429 254 631
--------- --------- --------- ---------
6,906 3,015 12,884 38,271
--------- --------- --------- ---------
Costs and Expenses:
Lease operating expenses............................................ 1,029 819 3,065 3,823
Production taxes.................................................... 258 283 893 1,482
Depreciation, depletion and amortization............................ 2,979 1,081 5,375 6,551
General and administrative, net..................................... 838 802 2,441 3,014
Interest expense.................................................... 316 27 487 2,245
--------- --------- --------- ---------
5,420 3,012 12,261 17,115
--------- --------- --------- ---------
Income before income taxes............................................ 1,486 3 623 21,156
Income Tax Provision.................................................. (520) (1) (218) (5,695)
--------- --------- --------- ---------
Net Income............................................................ $ 966 $ 2 $ 405 $ 15,461
--------- --------- --------- ---------
--------- --------- --------- ---------
Earnings per share.................................................... $ 0.09 $ 0.00 $ 0.04 $ 1.44
--------- --------- --------- ---------
--------- --------- --------- ---------
Weighted Average Common Shares Outstanding............................ 10,757 10,701 10,720 10,700
--------- --------- --------- ---------
--------- --------- --------- ---------
</TABLE>
F-1
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
1997 1996
------------- -------------
(IN THOUSANDS,
EXCEPT SHARE DATA)
<S> <C> <C>
ASSETS
Current Assets:
Cash and equivalents.............................................................. $ 1,314 $ 22,023
Accounts receivable............................................................... 6,488 5,108
Stockholder note receivable....................................................... 559 559
Prepaids and other................................................................ 3,783 2,203
------------- -------------
12,144 29,893
------------- -------------
Property and Equipment, at cost:
Oil and gas properties, under the full cost method of accounting
Proved.......................................................................... 129,345 78,641
Unproved........................................................................ 10,733 9,822
Less accumulated depreciation, depletion and amortization......................... (41,273) (36,581)
------------- -------------
98,805 51,882
Furniture and equipment, net...................................................... 2,165 2,918
------------- -------------
100,970 54,800
------------- -------------
Other Assets:....................................................................... 136 264
------------- -------------
$ 113,250 $ 84,957
------------- -------------
------------- -------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued expenses............................................. $ 11,919 $ 7,469
Accrued ad valorem taxes.......................................................... 2,192 2,040
Income taxes payable.............................................................. 42 1,000
Current portion of long-term debt................................................. 150 206
------------- -------------
14,303 10,715
------------- -------------
Long-term Debt, net of current portion.............................................. 23,092 218
Ad Valorem Taxes and Other.......................................................... 1,109 513
Deferred Income Taxes............................................................... 5,412 4,760
Commitments and Contingencies
Stockholders' Equity:
Preferred stock, par value $.01 per share; 10,000,000 shares authorized, no shares
issued and outstanding.......................................................... -- --
Common stock, par value $.01 per share, 50,000,000 shares authorized, 10,813,000
and 10,757,000 shares issued, respectively...................................... 108 108
Additional paid-in capital........................................................ 59,401 59,219
Retained earnings................................................................. 9,961 9,556
Common stock held in treasury, at cost, 56,000 shares............................. (136) (132)
------------- -------------
69,334 68,751
------------- -------------
$ 113,250 $ 84,957
------------- -------------
------------- -------------
</TABLE>
F-2
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOW
<TABLE>
<CAPTION>
FOR THE NINE MONTHS
ENDED
SEPTEMBER 30,
----------------------
1997 1996
---------- ----------
(IN THOUSANDS)
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income.............................................................................. $ 405 $ 15,461
Adjustments to reconcile net income to net cash provided by
operating activities--
Gain on sale of assets................................................................ -- (22,472)
Depreciation, depletion and amortization.............................................. 5,375 6,551
Deferred income tax provision......................................................... 652 3,695
Stock compensation expense............................................................ 182 81
Other, net............................................................................ (3) 116
Changes in operating assets and liabilities--
Decrease (increase) in--
Restricted cash................................................................... -- (55)
Receivables....................................................................... (803) 5,000
Prepaids and other................................................................ (1,456) (2,229)
(Decrease) increase in--
Accounts payable and accrued expenses............................................. (593) (1,826)
Ad valorem taxes and other........................................................ 748 (1,834)
Income taxes payable.............................................................. (958) 2,000
---------- ----------
Net cash provided by operating activities............................................. 3,549 4,488
---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital additions....................................................................... (47,267) (25,694)
Proceeds from sale of property and equipment............................................ 195 125,135
---------- ----------
Net cash provided by (used in) investing activities................................... (47,072) 99,441
---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from notes payable and long-term debt.......................................... 30,000 8,047
Principal payments on notes payable and long-term debt.................................. (7,182) (84,806)
Purchase of treasury stock and options.................................................. (4) (37)
Issuance of common stock................................................................ -- 84
---------- ----------
Net cash provided by (used in) financing activities................................... 22,814 (76,712)
---------- ----------
INCREASE (DECREASE) IN CASH AND EQUIVALENTS............................................... (20,709) 27,217
CASH AND EQUIVALENTS, beginning of period................................................. 22,023 1,613
---------- ----------
CASH AND EQUIVALENTS, end of period....................................................... $ 1,314 $ 28,830
---------- ----------
---------- ----------
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest.................................................................. $ 285 $ 2,300
---------- ----------
---------- ----------
Cash paid for income taxes.............................................................. $ 958 $ --
---------- ----------
---------- ----------
</TABLE>
F-3
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
FOR THE PERIOD FROM JANUARY 1, 1996 THROUGH SEPTEMBER 30, 1997
<TABLE>
<CAPTION>
COMMON STOCK ADDITIONAL TREASURY STOCK RETAINED
---------------------- PAID-IN ------------------------ EARNINGS
SHARES AMOUNT CAPITAL SHARES AMOUNT (DEFICIT)
--------- ----------- ----------- ----------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
BALANCES, January 1, 1996.............................. 10,724 $ 107 $ 59,288 (32) $ (94) $ (6,014)
Issuance and vesting of restricted stock and stock
options............................................ 33 1 181 -- -- --
Purchase of treasury stock and options............... -- -- (250) (24) (38) --
Net income......................................... -- -- -- -- -- 15,570
--
--------- ----- ----------- ----- -----------
BALANCES, December 31, 1996............................ 10,757 108 59,219 (56) (132) 9,556
Issuance and vesting of restricted stock............. 56 -- 182 -- -- --
Purchase of treasury stock........................... -- -- -- -- (4) --
Net income......................................... -- -- -- -- -- 405
--
--------- ----- ----------- ----- -----------
BALANCES, September 30, 1997........................... 10,813 $ 108 $ 59,401 (56) $ (136) $ 9,961
--
--
--------- ----- ----------- ----- -----------
--------- ----- ----------- ----- -----------
<CAPTION>
TOTAL
STOCKHOLDERS'
EQUITY
------------
<S> <C>
BALANCES, January 1, 1996.............................. $ 53,287
Issuance and vesting of restricted stock and stock
options............................................ 182
Purchase of treasury stock and options............... (288)
Net income......................................... 15,570
------------
BALANCES, December 31, 1996............................ 68,751
Issuance and vesting of restricted stock............. 182
Purchase of treasury stock........................... (4)
Net income......................................... 405
------------
BALANCES, September 30, 1997........................... $ 69,334
------------
------------
</TABLE>
F-4
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
NOTE TO CONSOLIDATED FINANCIAL STATEMENTS
(1) UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
In the opinion of management, the accompanying unaudited consolidated
financial statements contain all adjustments (consisting only of normal
recurring items) necessary to present fairly the financial position of Basin
Exploration, Inc. and its wholly-owned subsidiaries (collectively, "Basin" or
the "Company") as of September 30, 1997 and the results of operations and cash
flows for the periods presented. Certain information and footnote disclosures
normally included in financial statements prepared in accordance with generally
accepted accounting principles have been condensed or omitted pursuant to the
Securities and Exchange Commission's rules and regulations. The results of
operations for the periods presented are not necessarily indicative of the
results to be expected for the full year. Management believes the disclosures
made are adequate to ensure that the information is not misleading and suggests
that these financial statements be read in conjunction with the Company's
Consolidated Financial Statements and Notes included elsewhere in this
Prospectus Supplement.
F-5
<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, 1996 and 1995, and the
related consolidated statements of operations, changes in stockholders' equity
and cash flow for each of the three years in the period ended December 31, 1996.
These consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
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 state-ment presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position of
Basin Exploration, Inc. and subsidiaries as of December 31, 1996 and 1995, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 1996, in conformity with generally accepted
accounting principles.
ARTHUR ANDERSEN LLP
Denver, Colorado,
February 14, 1997.
F-6
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1996 1995 1994
--------- ---------- ---------
(IN THOUSANDS,
EXCEPT PER SHARE DATA)
<S> <C> <C> <C>
Revenue:
Oil sales..................................................................... $ 11,292 $ 19,632 $ 19,971
Gas sales..................................................................... 6,890 20,013 24,255
Gain on sale of assets........................................................ 22,472 -- --
Interest and other............................................................ 1,009 831 161
--------- ---------- ---------
41,663 40,476 44,387
--------- ---------- ---------
Costs and Expenses:
Lease operating expenses...................................................... 4,776 8,196 8,642
Production taxes.............................................................. 1,829 3,478 3,432
Depreciation, depletion and amortization...................................... 7,606 17,202 18,163
General and administrative, net............................................... 3,850 5,498 4,641
Interest expense.............................................................. 2,254 6,432 3,618
Property impairment........................................................... -- 26,500 --
Other......................................................................... 18 497 --
--------- ---------- ---------
20,333 67,803 38,496
--------- ---------- ---------
Income (Loss) Before Income Taxes............................................... 21,330 (27,327) 5,891
Income Tax (Provision) Benefit.................................................. (5,760) 7,784 (2,236)
--------- ---------- ---------
Net Income (Loss)............................................................... $ 15,570 $ (19,543) $ 3,655
--------- ---------- ---------
--------- ---------- ---------
Earnings (Loss) Per Share....................................................... $ 1.45 $ (1.82) $ 0.34
--------- ---------- ---------
--------- ---------- ---------
Weighted Average Common Shares Outstanding...................................... 10,700 10,710 10,813
--------- ---------- ---------
--------- ---------- ---------
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-7
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------
1996 1995
---------- ----------
(IN THOUSANDS)
<S> <C> <C>
ASSETS
Current Assets:
Cash and equivalents.................................................................... $ 22,023 $ 1,613
Accounts receivable..................................................................... 5,108 7,029
Stockholder note receivable............................................................. 559 559
Inventory and other..................................................................... 2,203 1,116
---------- ----------
29,893 10,317
---------- ----------
Property and Equipment, at cost:
Oil and gas properties, under the full cost method of
accounting--
Proved................................................................................ 78,641 206,880
Unproved.............................................................................. 9,822 5,001
Less accumulated depreciation, depletion and amortization............................... (36,581) (80,961)
---------- ----------
51,882 130,920
Furniture and equipment, net............................................................ 2,918 3,678
---------- ----------
54,800 134,598
---------- ----------
Other Assets:
Restricted cash......................................................................... -- 578
Other, net.............................................................................. 264 1,158
---------- ----------
264 1,736
---------- ----------
$ 84,957 $ 146,651
---------- ----------
---------- ----------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued expenses................................................... $ 7,469 $ 7,985
Accrued ad valorem taxes................................................................ 2,040 4,368
Income taxes payable.................................................................... 1,000 --
Current portion of long-term debt....................................................... 206 175
---------- ----------
10,715 12,528
---------- ----------
Long-term Debt, net of current portion.................................................... 218 77,172
Ad Valorem Taxes and Other Deferred Income Taxes.......................................... 513 3,664
Commitments and Contingencies (Note 6).................................................... 4,760 --
Stockholders' Equity:
Preferred stock, par value $0.01 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 10,724,000
shares issued and outstanding, respectively........................................... 108 107
Additional paid-in capital.............................................................. 59,219 59,288
Retained earnings (accumulated deficit)................................................. 9,556 (6,014)
Common stock held in treasury, at cost, 56,000 and 32,000 shares, respectively.......... (132) (94)
---------- ----------
68,751 53,287
---------- ----------
$ 84,957 $ 146,651
---------- ----------
---------- ----------
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-8
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOW
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1996 1995 1994
---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)........................................................... $ 15,570 $ (19,543) $ 3,655
Adjustments to reconcile net income loss) to
net cash provided by operating activities--
Gain on sale of assets.................................................... (22,472) -- --
Depreciation, depletion and amortization.................................. 7,606 17,202 18,163
Deferred income tax expense (benefit)..................................... 4,760 (7,784) 2,470
Property impairment....................................................... -- 26,500 --
Stock compensation expense................................................ 98 302 354
Amortization of debt issuance costs....................................... 118 373 331
Changes in operating assets and liabilities--
Decrease (increase) in--
Restricted cash......................................................... 578 (75) 2,742
Receivables............................................................. 1,664 2,594 (2,934)
Inventory and other..................................................... (1,861) 206 (928)
(Decrease) increase in--
Accounts payable and accrued expenses................................... 103 (6,947) 2,814
Ad valorem taxes........................................................ (2,255) (1,073) 1,968
Unearned income......................................................... -- (1,435) 876
Income taxes payable.................................................... 1,000 -- (250)
---------- ---------- ----------
Net cash provided by operating activities............................... 4,909 10,320 29,261
---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital additions........................................................... (27,741) (17,782) (62,321)
Proceeds from sale of property and equipment................................ 125,625 3,941 847
Asset sale transaction costs................................................ (5,257) -- --
Payments received on notes receivable....................................... -- -- 136
---------- ---------- ----------
Net cash provided by (used in) investing activities..................... 92,627 (13,841) (61,338)
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from notes payable and long-term debt.............................. 8,594 4,937 39,154
Principal payments on notes payable and long-term debt...................... (85,517) (5,150) (3,988)
Proceeds from sale of stock, net............................................ 84 -- (54)
Purchase of treasury stock and options...................................... (287) (47) (27)
---------- ---------- ----------
Net cash (used in) provided by financing activities..................... (77,126) (260) 35,085
---------- ---------- ----------
INCREASE (DECREASE) IN CASH AND EQUIVALENTS................................... 20,410 (3,781) 3,008
CASH AND EQUIVALENTS, beginning of year....................................... 1,613 5,394 2,386
---------- ---------- ----------
CASH AND EQUIVALENTS, end of year............................................. $ 22,023 $ 1,613 $ 5,394
---------- ---------- ----------
---------- ---------- ----------
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest...................................................... $ 2,327 $ 6,111 $ 3,095
Cash paid for taxes......................................................... $ -- $ -- $ 156
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-9
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
-----------------------------------------------------------------------------
RETAINED
COMMON STOCK ADDITIONAL TREASURY STOCK EARNINGS
------------------------ PAID-IN ------------------------ (ACCUMULATED
SHARES AMOUNT CAPITAL SHARES AMOUNT DEFICIT)
----------- ----------- ----------- ----------- ----------- ------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
BALANCES, December 31, 1993....................... 10,665 $ 107 $ 57,222 (1) $ (20) $ 9,874
Offering costs.................................... -- -- (54) -- -- --
Purchase of treasury stock........................ -- -- -- (12) (27) --
Issuance of warrants.............................. -- -- 1,464 -- -- --
Issuance and vesting of restricted stock and stock
options......................................... 27 -- 354 -- -- --
Net income........................................ -- -- -- -- -- 3,655
--
----------- ----- ----------- ----- ------------
BALANCES, December 31, 1994....................... 10,692 107 58,986 (13) (47) 13,529
Purchase of treasury stock........................ -- -- -- (19) (47) --
Issuance and vesting of restricted stock and stock
options......................................... 32 -- 302 -- -- --
Net loss.......................................... -- -- -- -- -- (19,543)
--
----------- ----- ----------- ----- ------------
BALANCES, December 31, 1995....................... 10,724 107 59,288 (32) (94) (6,014)
Purchase of treasury stock and options............ -- -- (250) (24) (38) --
Issuance and vesting of restricted stock and stock
options......................................... 33 1 181 -- -- --
Net income........................................ -- -- -- -- -- 15,570
--
----------- ----- ----------- ----- ------------
BALANCES, December 31, 1996....................... 10,757 $ 108 $ 59,219 (56) $ (132) $ 9,556
--
--
----------- ----- ----------- ----- ------------
----------- ----- ----------- ----- ------------
<CAPTION>
STOCKHOLDERS'
EQUITY
------------
<S> <C>
BALANCES, December 31, 1993....................... $ 67,183
Offering costs.................................... (54)
Purchase of treasury stock........................ (27)
Issuance of warrants.............................. 1,464
Issuance and vesting of restricted stock and stock
options......................................... 354
Net income........................................ 3,655
------------
BALANCES, December 31, 1994....................... 72,575
Purchase of treasury stock........................ (47)
Issuance and vesting of restricted stock and stock
options......................................... 302
Net loss.......................................... (19,543)
------------
BALANCES, December 31, 1995....................... 53,287
Purchase of treasury stock and options............ (288)
Issuance and vesting of restricted stock and stock
options......................................... 182
Net income........................................ 15,570
------------
BALANCES, December 31, 1996....................... $ 68,751
------------
------------
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-10
<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 9), and pays vendors for
oil and gas services. Joint interest receivables are subject to collection under
terms of operating agreements which generally provide lien rights.
The accompanying financial statements present the operations of the Company
on a consolidated basis. All significant intercompany accounts and transactions
have been eliminated in consolidation. The preparation of financial statements
in conformity with generally accepted accounting principles requires management
to make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Certain reclassifications have been made to amounts reported in previous
years to conform to 1996 presentation.
CASH EQUIVALENTS--Cash equivalents are comprised of highly liquid
instruments with original maturities of three months or less. The total carrying
amount of cash and equivalents approximates the fair value of such instruments.
OIL AND GAS PROPERTIES--The Company follows the full cost method of
accounting for oil and gas properties. Under this method, all costs associated
with the development, exploration and acquisition of oil and gas properties are
capitalized in the Company's one cost center (full cost pool), which is the
continental United States including the Gulf of Mexico. Payroll and other
internal costs capitalized include salaries and related fringe benefits paid to
employees directly engaged in the acquisition, exploration and development of
oil and gas properties as well as all other directly identifiable, internal
costs associated with these activities. Payroll and other internal costs
associated with production operations and general corporate activities are
expensed in the period incurred. Future development, site restoration,
dismantlement and abandonment costs, net of salvage values, are estimated on a
property-by-property basis based on prevailing prices and are amortized to
expense, along with the capitalized costs discussed above, using the
unit-of-production method based upon actual production and estimates of proved
reserve quantities. Accumulated depreciation, depletion and amortization is
recorded on the balance sheet as a reduction to property, plant and equipment
costs. Proceeds from sales of oil and gas properties are credited to the full
cost pool with no gain or loss recognized unless such adjustments would
significantly alter the relationship between capitalized costs and proved
reserves of oil and gas.
If capitalized costs, net of amortization and related deferred taxes, exceed
the full cost ceiling, the excess would be expensed in the period such excess
occurs. The full cost ceiling includes an estimate of the discounted value of
future net revenues attributable to proven reserves, using various assumptions
and parameters consistent with promulgations of the Securities and Exchange
Commission. The full cost ceiling may be particularly sensitive to changes in
prevailing oil and gas sales prices or forecast production rates. The Company
recognized $26,500,000 of such impairment at September 30, 1995.
The Company invests in unevaluated oil and gas properties and related assets
for the purpose of future exploration for proved reserves. The costs of such
assets are included in unproved oil and gas properties at the lower of cost or
estimated fair market value.
F-11
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
INVENTORY--Inventory of lease and well equipment is stated at the lower of
cost or market determined using the specific identification method.
FURNITURE AND EQUIPMENT--Furniture and equipment is depreciated over
estimated useful lives of five to seven years. Maintenance and repair costs are
expensed as incurred.
INCOME TAXES--The Company computes income taxes in accordance with Statement
of Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income
Taxes." SFAS 109 requires an asset and liability approach which results in the
recognition of deferred tax liabilities and assets for the expected future tax
consequences of temporary differences between the carrying amounts and the tax
bases of those assets and liabilities. SFAS 109 also requires the recording of a
valuation allowance if it is more likely than not that some portion or all of a
deferred tax asset will not be realized.
HEDGING ACTIVITIES--The Company periodically enters into agreements with
third parties to hedge against the effects of fluctuations in future oil and gas
prices. Gains or losses on such agreements are deferred and recognized as oil
and gas revenue when the hedged production occurs.
At December 31, 1996, the Company was a party to a crude oil swap agreement
and a crude oil collar arrangement, each with a contract volume of 10,000
barrels per month through December 31, 1997. The swap agreement provides for the
cash settlement of the differential between the $18.32 per barrel contract price
and the average closing NYMEX crude oil price during each month. The collar
arrangement provides for the cash settlement of the differential between the
monthly average closing NYMEX price and the contract floor of $19.50 per barrel
or the contract ceiling of $24.35 per barrel, if the monthly average closing
NYMEX price falls outside of the range defined by such contract floor and
contract ceiling. In accordance with SFAS 107, "Disclosures About Fair Value of
Financial Instruments," the Company has estimated the fair value of its hedging
arrangements utilizing the NYMEX crude oil strip at December 31, 1996. While it
is not the Company's intention to terminate either of the arrangements, it is
estimated that the Company would have been required to pay approximately
$525,000 to terminate the arrangements on December 31, 1996. As of February 12,
1997, the estimated cost to terminate such arrangements was approximately
$325,000, inclusive of the actual cost of contract settlements through that
date. Due to the volatility of crude oil prices, the fair market value may not
be representative of the actual gain or loss that will be realized by the
Company in 1997.
The Company recognized a reduction in oil revenue of $480,000, $115,000 and
$95,000 under hedging agreements in 1996, 1995 and 1994, respectively. The
Company recognized a reduction in gas revenue of $206,000 under hedging
agreements in 1994.
EARNINGS (LOSS) PER SHARE--Earnings (loss) per share have been computed
based on the weighted average number of common shares outstanding. The impact of
dilutive common stock equivalents on earnings (loss) per share was immaterial.
(2) RESTRICTED CASH
WELL PLUGGING--The Company was required under a certain farmout agreement to
deposit in an escrow account amounts for future plugging and abandonment costs
beyond a one-year time period. The total cash held in escrow at December 31,
1995, was $578,000. Such escrow account was closed and the funds were released
to the Company in November 1996.
F-12
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(3) ACQUISITIONS AND DIVESTITURES OF OIL AND GAS PROPERTIES
In February 1996, the Company entered into agreements pursuant to which it
sold all of its assets in the D-J Basin in two transactions closed in March and
June 1996, for an aggregate sales price of $123,500,000, effective January 1,
1996. Combined, these transactions resulted in Basin selling its interests in
approximately two-thirds of its producing wells and 70% of its proved oil and
gas reserves at December 31, 1995. Because the second transaction constituted
the sale of a significant portion of the Company's total oil and gas reserves
which would significantly alter the relationship between the Company's
capitalized costs and its proved reserves, net capitalized costs of oil and gas
properties were allocated between the reserves sold and retained based upon
their estimated relative reserve quantities as of June 7, 1996 and a resulting
gain of approximately $22,500,000 was recognized. A portion of the proceeds from
the sales was used to payoff all outstanding bank debt and residual proceeds,
net of transaction costs, were invested in short-term interest bearing cash
equivalents. Revenue and expenses associated with the sold properties were
included in the Company's results of operations through the respective closing
dates.
In November 1994 the Company acquired all of the outstanding stock of
Sterling Energy Corp. ("Sterling") for aggregate consideration of approximately
$15.4 million consisting of approximately $10.1 million in cash, the assumption
of $3.6 million of net liabilities, warrants to purchase 300,000 shares of the
Company's common stock at an exercise price of $14.00 valued at $1.5 million,
and $.2 million in transaction expenses. The acquisition included producing and
non-producing oil and gas properties and undeveloped acreage located in the
Scott and Draw fields in Converse County, Wyoming and in the Tohonadla field in
San Juan County, Utah, as well as a gas processing plant located in Wyoming. The
acquisition was funded partially with an increased revolving credit facility.
The Company accounted for the Sterling acquisition using purchase accounting and
began consolidating the results as of the December 1994 close date.
(4) LONG-TERM DEBT
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------
1996 1995
--------- ---------
(IN THOUSANDS)
<S> <C> <C>
Revolving credit facility................................................. $ 0 $ 77,000
Other Notes............................................................... 424 347
--------- ---------
424 77,347
Less: Current portion..................................................... (206) (175)
--------- ---------
Long-term debt, net of current portion.................................... $ 218 $ 77,172
--------- ---------
--------- ---------
</TABLE>
On August 6, 1996, the Company entered into an Amended and Restated Credit
Facility with its existing bank group. The initial borrowing base was set at
$25,000,000 and is scheduled to be determined as of April 30, 1997 for the
following six month period. The Credit Facility provides for the interest rate
on borrowings to be determined based on the prime rate or LIBOR, at the
Company's election. A varying spread above the prime rate ranging from 0% to
0.5% and over LIBOR ranging from 0.625% to 1.25% will be applied based upon the
Company's applicable debt-to-capitalization ratio. The Credit Facility provides
for borrowings to be revolving loans until August 1, 1999, at which time the
outstanding balance is scheduled to convert to a four year amortizing term loan.
The Credit 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. The note may be secured by the Company's oil and gas
properties in certain
F-13
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(4) LONG-TERM DEBT (CONTINUED)
circumstances, at the election of the lending banks. There were no borrowings
outstanding under the facility at December 31, 1996.
Effective May 31, 1995, in order to improve management of interest rate
risk, Basin entered into an interest rate swap agreement. Under the agreement,
the Company fixed the LIBOR reference rate on a notional amount of $50 million
at 6 percent per annum through May 31, 1996.
Debt is payable as follows (in thousands):
<TABLE>
<S> <C>
1997................................................................. $ 206
1998................................................................. 152
1999................................................................. 66
---------
$ 424
---------
---------
</TABLE>
(5) BENEFIT PLANS
401(K) SAVINGS--The Company has a 401(k) profit sharing plan (the "Plan").
Eligible employees may make voluntary contributions to the Plan, which may be
matched by the Company, at its discretion, up to 6 percent of the employee's
eligible compensation. The Company has historically matched the first three
percent of employees' eligible compensation that is contributed under the Plan.
The amount of employee contributions is limited as specified in the Plan. The
Company may, at its discretion, make additional contributions to the Plan. The
Company expensed $96,000, $195,000, and $261,000, with respect to the Plan for
the years ended December 31, 1996, 1995 and 1994, respectively.
STOCK PLAN--Under the Company's Employees' Equity Incentive Plan and
Non-Employee Directors' Stock Option Plan, officers, key employees, consultants
and directors of the Company are eligible to receive incentive stock options,
non-qualified stock options and restricted stock. At December 31, 1996, a total
of approximately 1,365,000 shares were available for grant under the plans.
Shares granted generally vest over three to four years, and expire after ten
years. A total of 684,000 shares of the Company's common stock are subject to
such plans as of December 31, 1996, including 35,000 unvested shares of
restricted stock and 649,000 outstanding stock options.
The following table summarizes the changes in stock options:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1996 1995 1994
---------- ---------- ---------
<S> <C> <C> <C>
Balance, beginning of period............................... 702,500 541,833 426,833
Granted.................................................... 252,500 265,000 115,000
Exercised.................................................. (33,500) -- --
Forfeited/Canceled......................................... (272,500) (104,333) --
---------- ---------- ---------
Balance, end of period..................................... 649,000 702,500 541,833
---------- ---------- ---------
---------- ---------- ---------
</TABLE>
F-14
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(5) BENEFIT PLANS (CONTINUED)
At December 31, 1996, the weighted average exercise price and weighted average
remaining life for options outstanding was $6.55 per share and 8.3 years,
respectively. Additional information regarding the outstanding options at
December 31, 1996, is as follows.
<TABLE>
<CAPTION>
NUMBER OF NUMBER OF
OPTIONS OPTIONS RANGE OF EXERCISE
OUTSTANDING EXERCISABLE PRICES PER SHARE
- ----------- ----------- -----------------
<S> <C> <C>
54,000 53,167 $11.00 - $14.50
112,500 94,167 $ 7.63 - $ 9.50
235,000 51,667 $ 5.13 - $ 6.88
247,500 25,833 $ 3.88 - $ 4.94
- ----------- -----------
649,000 224,834
- ----------- -----------
- ----------- -----------
</TABLE>
In connection with its initial public offering ("IPO") in 1992, the Company
granted options to two officers to purchase 100,000 shares each of the Company's
common stock at a price substantially below the IPO price of $9.50 per share.
The Company recognized compensation expense related to these options of
approximately $97,000 and $233,000 for the years ended December 31, 1995 and
1994, respectively.
The Company granted 25,000, 32,000, and 25,000 shares of restricted stock
during 1996, 1995 and 1994, respectively. Related compensation expense was
recognized in the amounts of approximately $98,000, $205,000, and $121,000 for
the years ended December 31, 1996, 1995, and 1994, respectively. Cumulatively
through December 31, 1996, 35,000 shares of restricted stock remained subject to
forfeiture, 48,000 shares of restricted stock had been forfeited and 42,000
shares were no longer subject to restriction.
In connection with the Sterling acquisition, the Company issued warrants to
purchase 300,000 shares of the Company's common stock at an exercise price of
$14.00 per share. Such warrants became exercisable on October 13, 1994 and have
an expiration date of December 31, 1999.
In October 1995, the Financial Accounting Standards Board issued SFAS 123,
"Accounting for Stock-Based Compensation". SFAS 123 was effective for 1996 and
recommends a fair value based method of accounting for employee stock
compensation, including stock options. However, companies may choose to account
for stock compensation using the intrinsic value based method as prescribed by
Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees" and provide pro forma disclosures of net income and earnings per
share as if the fair value based method had been applied. The Company has
elected to continue to account for stock compensation using the intrinsic value
based method.
Had the Company elected to follow SFAS 123, the fair value of each option
grant would have been estimated on the date of grant using the Black-Sholes
option-pricing model with the following weighted-average assumptions used for
grants in 1996 and 1995: risk free interest rate of 6.75%; expected dividend
yield of 0%; expected life of 5 years; and expected volatility of 55%. Based
upon these assumptions, the weighted average fair value of options granted
during 1996 and 1995 was $2.73 and $2.96 per share, respectively. SFAS 123 would
have had no significant impact on reported operating results for the years ended
December 31, 1996 and 1995.
F-15
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(6) COMMITMENTS AND CONTINGENCIES
LEASES--The Company is the primary obligor under various noncancelable
office space operating lease arrangements. The Company also subleases certain
office space to and from third parties under various noncancellable lease
arrangements. The following is a schedule of future minimum lease payments under
these leases:
<TABLE>
<CAPTION>
FUTURE FUTURE
MINIMUM MINIMUM
LEASE LEASE
OBLIGATIONS RECEIPTS
----------- -----------
(IN THOUSANDS)
<S> <C> <C>
1997.................................................................. $ 955 $ 501
1998.................................................................. 955 501
1999.................................................................. 923 478
2000.................................................................. 107 --
----------- -----------
$ 2,940 $ 1,480
----------- -----------
----------- -----------
</TABLE>
Payments related to these leases obligations were approximately $707,000,
$710,000, and $435,000 for the years ended December 31, 1996, 1995 and 1994,
respectively.
LEGAL PROCEEDINGS--The Company, from time to time, is involved in various
legal and administrative proceedings and claims of various types which arise in
the ordinary course of its business. While any litigation contains an element of
uncertainty, in the opinion of management, none of these actions, either
individually or in the aggregate will have a material adverse effect on the
Company's financial condition, liquidity or results of operations.
(7) INCOME TAXES
The components of the provision (benefit) for income taxes are as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------
1996 1995 1994
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Current provision (benefit):
Federal....................................................... $ 950 $ -- $ (234)
State......................................................... 50 -- --
--------- --------- ---------
1,000 -- (234)
--------- --------- ---------
Deferred provision (benefit):
Federal....................................................... 4,760 (6,970) 2,176
State......................................................... -- (814) 294
4,760 (7,784) 2,470
--------- --------- ---------
Provision (benefit) for income taxes............................ $ 5,760 $ (7,784) $ 2,236
--------- --------- ---------
--------- --------- ---------
</TABLE>
F-16
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(7) INCOME TAXES (CONTINUED)
Reconciliations of income tax provisions (benefit) computed at the federal
statutory rate with income tax provisions recorded by the Company for each of
the past three years are as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1996 1995 1994
--------- ---------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Income (loss) before income taxes............................ $ 21,330 $ (27,327) $ 5,891
--------- ---------- ---------
--------- ---------- ---------
Computed tax at the applicable federal statutory rate........ $ 7,252 $ (9,291) $ 2,003
State income tax, net of federal tax benefits................ 704 (689) 194
Deferred tax assets valuation allowance...................... (2,196) 2,196 --
Other........................................................ -- -- 39
--------- ---------- ---------
Income tax provision (benefit)............................... $ 5,760 $ (7,784) $ 2,236
--------- ---------- ---------
--------- ---------- ---------
</TABLE>
The tax effects of significant temporary differences representing deferred
tax assets and liabilities are as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------
1996 1995
--------- ---------
(IN THOUSANDS)
<S> <C> <C>
Deferred tax liabilities:
Oil and gas properties and equipment................................... $ 6,235 $ 2,315
--------- ---------
Deferred tax assets:
Alternative minimum tax credit carry forward........................... (1,475) (545)
Net operating loss carry forwards...................................... -- (3,914)
Other.................................................................. -- (52)
Less deferred tax assets valuation allowance........................... -- 2,196
--------- ---------
(1,475) (2,315)
--------- ---------
Net deferred tax liability............................................... $ 4,760 $ --
--------- ---------
--------- ---------
</TABLE>
As of December 31, 1996, the Company has alternative minimum tax credit
carry forwards for income tax purposes of approximately $1,475,000 which may be
utilized to reduce future tax liability of the Company. These carry forwards
have no expiration date.
(8) RELATED PARTY TRANSACTIONS
Prior to the IPO, the Company advanced $559,000 to its principal stockholder
at an annual interest rate of 9 percent. The note was amended in 1996 and the
balance is now due in December 1997 with interest only payments due quarterly.
(9) OIL AND GAS ACTIVITIES
The Company's oil and gas operations are conducted in the United States.
Certain information concerning these activities follows:
F-17
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(9) OIL AND GAS ACTIVITIES (CONTINUED)
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 1996 1995 1994
- ---------------------------------------------------------------------- --------- --------- ---------
<S> <C> <C> <C>
PanEnergy............................................................. 43% 62% 77%
Eighty-Eight Oil Company.............................................. 26% 16% (a)
</TABLE>
- ------------------------
(a) less than ten percent
SECTION 29 TAX CREDITS--The Company received $1.5 million and $3 million in
1995 and 1994 respectively, for Section 29 tax credits associated with gas
production from various oil and gas properties of the Company. Such proceeds
were recorded as unearned income and recognized as incremental gas revenues as
the gas was produced and the credits earned. The Company recognized
approximately $2,857,000 and $2,123,000 of additional gas revenue during the
years ended December 31, 1995 and 1994, respectively, related to the
amortization of this unearned income.
COSTS INCURRED--Costs incurred in oil and gas operations and related
depreciation, depletion and amortization per equivalent unit-of-production are
as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------
1996 1995 1994
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Property acquisition:
Unproved................................................ $ 5,056(1) $ 2,429 $ 5,275
Proved.................................................. 3,067 3,889 16,751
Exploration costs......................................... 10,250 2,003 2,361
Development costs......................................... 4,472 7,427 42,113
--------- --------- ---------
Gross expenditures........................................ $ 22,845 $ 15,748 $ 66,500
--------- --------- ---------
--------- --------- ---------
Depletion per one thousand cubic feet of gas equivalent... $ 0.82 $ 0.84 $ 0.77
--------- --------- ---------
--------- --------- ---------
</TABLE>
- ------------------------
(1) Excludes $4,914,000 of costs recouped through the resale of partial
interests in prospects to industry partners.
COSTS NOT BEING AMORTIZED--Oil and gas property costs not being amortized at
December 31, 1996, consisted of $9,822,000 of leasehold and seismic costs, of
which $9,058,000, $488,000 and $276,000 were incurred in 1996, 1995 and 1994,
respectively. The Company anticipates that substantially all unevaluated costs
will be classified as evaluated costs within the next three years.
UNAUDITED SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION
The determination of oil and gas reserves is complex and highly
interpretive. Assumptions used to estimate reserve information may significantly
increase or decrease such reserves in future periods. The estimates of reserves
are subject to continuing changes and, therefore, an accurate determination of
F-18
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(9) OIL AND GAS ACTIVITIES (CONTINUED)
reserves may not be possible for many years because of the time needed for
development, drilling, testing and studies of the reservoirs. The following
unaudited table, based upon estimates of onshore reserves prepared by the
Company's engineers and audited by Netherland, Sewell & Associates, Inc. at
December 31, 1996, 1995 and 1994 and estimates of offshore reserves prepared by
Ryder Scott Company Petroleum Engineers at December 31, 1996, sets forth the
estimated quantities of proved oil and gas reserves for the Company and the
changes in total proved reserves as of December 31, 1996, 1995, and 1994. All
such reserves are located in the United States.
ANALYSES OF CHANGES IN PROVED RESERVES
<TABLE>
<CAPTION>
OIL (MBBLS) GAS (MMCF)
----------- ----------
<S> <C> <C>
Balance, December 31, 1993................................................................. 11,270 148,688
Revisions................................................................................ (107) (9,539)
Extensions, discoveries and additions.................................................... 1,351 20,269
Production............................................................................... (1,278) (14,377)
Sales of reserves in-place............................................................... (46) (664)
Purchases of reserves in-place........................................................... 3,951 11,953
----------- ----------
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
----------- ----------
----------- ----------
Proved developed reserves:
December 31, 1994........................................................................ 10,544 128,664
----------- ----------
----------- ----------
December 31, 1995........................................................................ 8,397 106,410
----------- ----------
----------- ----------
December 31, 1996........................................................................ 4,046 19,182
----------- ----------
----------- ----------
</TABLE>
F-19
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(9) OIL AND GAS ACTIVITIES (CONTINUED)
STANDARDIZED MEASURE
The unaudited standardized measure of discounted future net cash flows
related to proved oil and gas reserves are as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------------
1996 1995 1994
----------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Future production revenues....................................... $ 289,105 $ 439,415 $ 505,636
Future production costs.......................................... (108,522) (155,087) (163,244)
Future development costs......................................... (20,583) (45,907) (49,293)
Future income taxes.............................................. (39,101) (25,644) (45,252)
----------- ----------- -----------
Future net cash flows............................................ 120,899 212,777 247,847
Discount......................................................... (57,593) (95,529) (106,495)
----------- ----------- -----------
Standardized measure of discounted future net cash flows(1)...... $ 63,306 $ 117,248 $ 141,352
----------- ----------- -----------
----------- ----------- -----------
</TABLE>
- ------------------------
(1) Total future net cash flows before income taxes discounted at 10% per annum
are $83,656,000, $129,068,000 and $162,858,000 as of December 31, 1996, 1995
and 1994, respectively.
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.
F-20
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(9) OIL AND GAS ACTIVITIES (CONTINUED)
A summary of changes in the standardized measure of discounted future net
cash flows is as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1996 1995 1994
---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure of discounted future net cash flows, beginning
of year........................................................... $ 117,248 $ 141,352 $ 110,227
Changes in sales prices and production costs....................... 17,693 (8,382) (5,688)
Changes in estimated future development costs...................... (1,819) 448 4,407
Sales of minerals-in-place......................................... (83,530) (3,866) (339)
Purchase of minerals-in-place...................................... 10,887 2,696 26,849
Revisions of previous quantity estimates........................... (169) (18,026) (7,604)
Costs incurred that reduced future development costs............... -- 5,422 24,421
Extensions, discoveries and improved recovery...................... 16,286 7,086 13,397
Sales of oil and gas, net of production costs and taxes............ (11,577) (27,971) (32,152)
Accretion of discount.............................................. 12,907 16,286 13,648
Net change in future income taxes.................................. (8,530) 9,665 4,743
Changes in production rates (timing) and other..................... (6,090) (7,462) (10,557)
---------- ---------- ----------
Standardized measure of discounted future net cash flows, end of
year.............................................................. $ 63,306 $ 117,248 $ 141,352
---------- ---------- ----------
---------- ---------- ----------
</TABLE>
There are numerous uncertainties inherent in estimating quantities of proved
reserves and projected future rates of production and timing of development
expenditures, including many factors beyond the control of the producer. The
reserve data and standardized measures set forth herein represent only
estimates. Reserve engineering is a subjective process of estimating underground
accumulations of oil and gas that cannot be measured in an exact way, and the
accuracy of any reserve estimate is a function of the quality of available data
and of engineering and geological interpretation and judgment. As a result,
estimates of different engineers often vary. In addition, results of drilling,
testing and production subsequent to the date of an estimate may justify
revision of such estimates. Accordingly, reserve estimates are often different
from the quantities of oil and gas that are ultimately recovered. Further, the
estimated future net revenues from proved reserves and the present value thereof
are based upon certain assumptions, including geologic success, prices, future
production levels and costs, that may not prove correct over time. Predictions
of future production levels are subject to great uncertainty, and the
meaningfulness of such estimates is highly dependent upon the accuracy of the
assumptions upon which they are based. Oil and gas prices have fluctuated widely
in recent years. The calculated weighted average sales prices utilized for the
purposes of estimating the Company's proved reserves and future net revenue were
and $25.35 per
F-21
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(9) OIL AND GAS ACTIVITIES (CONTINUED)
barrel of oil and $3.02 per Mcf of gas at December 31, 1996, $18.64 per barrel
of oil and $1.56 per Mcf of gas at December 31, 1995 and $16.44 per barrel of
oil and $1.63 per Mcf of gas at December 31, 1994.
UNAUDITED SUPPLEMENTAL QUARTERLY FINANCIAL DATA
<TABLE>
<CAPTION>
FIRST SECOND THIRD FOURTH TOTAL
--------- --------- ---------- --------- ----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<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 common share............... (0.09) 1.53 -- 0.01 1.45
1995
Revenue........................................ $ 11,535 $ 10,192 $ 8,661 $ 10,088 $ 40,476
Gross profit from operations................... 8,220 7,136 5,561 7,054 27,971
Net income (loss).............................. 325 (271) (20,197) 600 (19,543)
Earnings (loss) per common share............... 0.03 (0.02) (1.88) 0.05 (1.82)
</TABLE>
F-22
<PAGE>
PROSPECTUS
$200,000,000
[LOGO]
BASIN EXPLORATION, INC.
DEBT SECURITIES
COMMON STOCK
PREFERRED STOCK
WARRANTS
Basin Exploration, Inc. (the "Company" or "Basin") may offer from time to
time (i) debt securities ("Debt Securities"), consisting of debentures, notes,
bonds and/or other unsecured evidences of indebtedness in one or more series,
(ii) shares of the Company's common stock, $.01 par value ("Common Stock"),
(iii) shares of preferred stock, $.01 par value ("Preferred Stock"), in one or
more series, or (iv) warrants to purchase Debt Securities, Preferred Stock or
Common Stock. The foregoing securities are collectively referred to as the
"Securities." Any Securities may be offered with other Securities or separately.
The Securities will be offered at an aggregate initial offering price not to
exceed US $200,000,000 or the equivalent (based on the applicable exchange rate
at the time of sale), if Debt Securities of the Company are issued in principal
amounts denominated in one or more foreign currencies or currency units as shall
be designated by the Company at prices and on terms to be determined at the time
of sale.
SEE "RISK FACTORS" FOR CERTAIN CONSIDERATIONS RELEVANT TO AN INVESTMENT IN
THE SECURITIES.
This Prospectus will be supplemented by one or more accompanying Prospectus
Supplements, which will set forth with regard to the particular Securities in
respect of which this Prospectus is being delivered (i) in the case of Debt
Securities, the title; aggregate principal amount; currency of denomination
(which may be in U.S. dollars, in any other currency, currencies or currency
unit, including the European Currency Unit); maturity; interest rate, if any
(which may be fixed or variable), or method of calculation thereof; time of
payment of any interest; form of payment of any interest whether in the form of
cash, additional Debt Securities, Common Stock or some combination thereof; any
terms for redemption at the option of the Company or the holder; any terms for
sinking fund payments; any index or other method used to determine the amounts
payable; the ranking of such Debt Securities (whether senior, senior
subordinated or subordinated); any conversion or exchange rights, at the option
of the Company or the holder; any listing on a securities exchange; the initial
public offering price and any other terms in connection with the offering and
sale of such Debt Securities; (ii) in the case of Common Stock, the number of
shares of Common Stock, the terms of the offering thereof and information
regarding the selling stockholder, if any; (iii) in the case of Preferred Stock,
the designation, stated value and liquidation preference per share; the initial
public offering price per share and the number of shares to be offered; dividend
rate (or method of calculation); dates on which dividends shall be payable and
dates from which dividends shall accrue; any redemption or sinking fund
provisions; any conversion or exchange rights; any listing of the Preferred
Stock on a securities exchange; and any other terms in connection with the
offering and sale of such Preferred Stock; and (iv) in the case of Warrants, the
number and terms thereof, the designation and the number of Securities issuable
upon their exercise; the exercise price; any listing of the Warrants or the
underlying Securities on a securities exchange and any other terms in connection
with the offering, sale and exercise of the Warrants. The Prospectus Supplement
will also contain information, as applicable, about certain United States
federal income tax considerations relating to the Securities in respect of which
this Prospectus is being delivered.
The Company's Common Stock is quoted on the Nasdaq National Market (Symbol:
"BSNX"). Each Prospectus Supplement will indicate if the Securities offered
thereby will be quoted on any market or listed on any securities exchange.
The Company may sell Securities to or through one or more underwriters, and
may also sell Securities directly to other purchasers or through agents. See
"Plan of Distribution." Each Prospectus Supplement will set forth the names of
any underwriters, dealers or agents involved in the sale of the Securities in
respect of which this Prospectus is being delivered, and any applicable fee,
commission or discount arrangements with them.
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE
SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION
PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY
REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
<PAGE>
THIS PROSPECTUS MAY NOT BE USED TO CONSUMMATE SALES OF SECURITIES UNLESS
ACCOMPANIED BY A PROSPECTUS SUPPLEMENT.
THE DATE OF THIS PROSPECTUS IS OCTOBER 2, 1997.
<PAGE>
AVAILABLE INFORMATION
The Company is subject to the informational requirements of the Securities
Exchange Act of 1934, as amended (the "Exchange Act"), and in accordance
therewith files reports, proxy statements and other information with the
Securities and Exchange Commission (the "Commission"). Such reports, proxy
statements and other information may be inspected and copied at the public
reference facilities of the Commission, Room 1024, Judiciary Plaza, 450 Fifth
Street, N.W., Washington, D.C. 20549, as well as at the following Regional
Offices: 7 World Trade Center, Suite 1300, New York, New York 10048, and
Citicorp Center, 500 West Madison Street, Suite 1400, Chicago, Illinois 60661.
Copies of such material can be obtained from the Commission by mail at
prescribed rates. Requests should be directed to the Commission's Public
Reference Section, Room 1024, Judiciary Plaza, 450 Fifth Street, N.W.,
Washington D.C. 20549. The Commission also maintains a website at
http://www.sec.gov that contains reports, proxy statements, and other
information. The Company's Common Stock is quoted on the Nasdaq National Market.
Reports, proxy and information statements and other information relating to the
Company can be inspected at the offices of the Nasdaq Stock Market, Inc., 1735 K
Street, Washington, D.C., 20006.
The Company has filed with the Commission a Registration Statement on Form
S-3 (herein, together with all amendments and exhibits, referred to as the
"Registration Statement") under the Securities Act of 1933 (the "Securities
Act") with respect to the Securities offered by this Prospectus. This
Prospectus, which forms part of the Registration Statement, does not contain all
of the information set forth in the Registration Statement, certain parts of
which have been omitted in accordance with the rules and regulations of the
Commission. For further information with respect to the Company and the
Securities, reference is hereby made to such Registration Statement, including
the exhibits filed therewith. The Registration Statement and the exhibits
thereto can be obtained by mail from or inspected and copied at the public
reference facilities maintained by the Commission as described in the prior
paragraph.
The Company distributes to its stockholders annual reports containing
audited consolidated financial statements and quarterly reports containing
unaudited financial information for the first three quarters of each year.
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
The following documents filed by the Company with the Commission are
incorporated by reference in this Prospectus:
(1) Annual Report on Form 10-K for the year ended December 31, 1996, filed
with the Commission on March 31, 1997;
(2) Amendment to Annual Report on Form 10-K for the year ended December 31,
1996 on Form 10-K/A-1, filed with the Commission on June 5, 1997;
(3) Quarterly Report on Form 10-Q for the period ended March 31, 1997, filed
with the Commission on May 15, 1997;
(4) Quarterly Report on Form 10-Q for the period ended June 30, 1997, filed
with the Commission on August 12, 1997;
(5) Registration Statement on Form 8-A filed with the Commission on February
27, 1996, relating to the Company's Stockholders' Rights Plan;
(6) The description of the Common Stock contained in the Company's
Registration Statement on Form 8-A dated April 24, 1992, filed with the
Commission on April 27, 1992.
All documents subsequently filed by the Company pursuant to Sections 13(a),
13(c), 14 or 15(d) of the Exchange Act prior to the termination of the offering
of the Securities offered hereby shall be deemed to be incorporated by reference
in this Prospectus and to be a part hereof from the date of filing of such
2
<PAGE>
documents. Any statement contained in a document incorporated or deemed to be
incorporated by reference shall be deemed to be modified or superseded for
purposes of this Prospectus to the extent that a statement contained herein or
in any other subsequently filed document, which also is or is deemed to be
incorporated by reference herein or in any Prospectus Supplement, modifies or
supersedes such statement. Any statement so modified or superseded shall not be
deemed, except as so modified or superseded, to constitute a part of this
Prospectus.
The Company will provide without charge to each person to whom a copy of
this Prospectus is delivered, on the oral or written request of such person, a
copy of any or all of the documents incorporated herein by reference (other than
exhibits, unless such exhibits are specifically incorporated by reference in
such documents). Requests for such copies should be directed to the Secretary,
370 Seventeenth Street, Suite 3400, Denver, Colorado 80202, telephone: (303)
685-8000, facsimile: (303) 685-8010.
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Prospectus includes and incorporates by reference statements that are
not purely historical and are "forward-looking statements" within the meaning of
Section 27A of the Securities Act and Section 21E of the Exchange Act. All
statements, other than statements of historical facts, included or incorporated
by reference in this Prospectus, involve risks and uncertainties that could
cause actual results to differ from projected results. Such statements address
activities, events or developments that the Company expects, believes, projects,
intends or anticipates will or may occur, including such matters as future
capital, development and exploration expenditures (including the amount and
nature thereof), drilling of wells, future production of oil and gas, business
strategies, cash flow and anticipated liquidity, prospect development and
property acquisition, or marketing of oil and gas. Factors that could cause
actual results to differ materially ("Cautionary Disclosures") include, among
others: general economic conditions, the market price of oil and natural gas,
the risks associated with exploration, the Company's ability to find, acquire,
market, develop and produce new properties, operating hazards attendant to the
oil and natural gas business, downhole drilling and completion risks that are
generally not recoverable from third parties or insurance, concentration of the
Company's production in a small number of properties in the Gulf of Mexico,
uncertainties in the estimation of proved reserves and in the projection of
future rates of production and timing of development expenditures, potential
mechanical failure 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 other factors described in this Prospectus and in any
Prospectus Supplement and in the Company's annual reports on Form 10-K,
quarterly reports on Form 10-Q and current reports on Form 8-K filed with the
Commission. Many of such factors are beyond the Company's ability to control or
predict. All forward-looking statements included or incorporated by reference in
this Prospectus are based on information available to the Company on the date
hereof, and the Company assumes no obligation to update such forward-looking
statements as a result of new information, future events or otherwise. Although
the Company believes that the assumptions and expectations reflected in such
forward-looking statements are reasonable, it can give no assurance that such
expectations will prove to have been correct or that the Company will take any
actions that may presently be planned. Prospective investors are cautioned not
to put undue reliance on forward-looking statements. Certain important factors
that could cause actual results to differ materially from the Company's
expectations are disclosed under "Risk Factors" and elsewhere in this
Prospectus. 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.
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<PAGE>
RISK FACTORS
PROSPECTIVE PURCHASERS OF THE SECURITIES SHOULD CAREFULLY READ THIS
PROSPECTUS, ANY PROSPECTUS SUPPLEMENT DELIVERED HEREWITH, AND THE DOCUMENTS
INCORPORATED BY REFERENCE HEREIN AND THEREIN. OWNERSHIP OF SECURITIES INVOLVES
CERTAIN RISKS. IN DETERMINING WHETHER TO PURCHASE THE SECURITIES, PROSPECTIVE
INVESTORS SHOULD CONSIDER CAREFULLY THE FOLLOWING RISK FACTORS AND THE OTHER
INFORMATION CONTAINED IN THIS PROSPECTUS, IN ADDITION TO THE OTHER RISK FACTORS
AND INFORMATION SET FORTH IN ANY PROSPECTUS SUPPLEMENT DELIVERED HEREWITH.
OIL AND GAS PRICES; HEDGING
Basin's revenues and profitability are substantially dependent upon
prevailing prices for oil, gas and natural gas liquids. For much of the past
decade, the markets for oil and natural gas have been extremely volatile. The
Company anticipates that such markets will continue to be volatile in the
foreseeable future. In general, future prices of oil, gas and natural gas
liquids are dependent upon numerous external factors such as various economic,
political and regulatory developments and competition from other sources of
energy. The unsettled nature of the energy market and the unpredictability of
worldwide political developments, including, for example, actions of OPEC
members, make it particularly difficult to estimate future prices of oil, gas
and natural gas liquids. Any significant decline in the price of oil, gas or
natural gas liquids for an extended period would have a material adverse effect
on the Company's financial condition and results of operations, and would, under
certain circumstances, result in a reduction in funds available under the
Company's bank credit facilities and impair access to other sources of capital.
From time to time, as conditions are deemed to warrant, the Company enters
into energy price swap arrangements to reduce its sensitivity to oil and gas
price volatility. Such arrangements are subject to a number of risks. If the
Company's reserves are not produced at the rates estimated by the Company due to
inaccuracies in the reserve estimation process, operational difficulties or
regulatory limitations, the Company would be required to satisfy its obligations
under hedging contracts on potentially unfavorable terms without the ability to
hedge that risk through sales of comparable quantities of its own production.
Further, the terms under which the Company enters into hedging contracts are
based on assumptions and estimates of numerous factors such as cost of
production and pipeline and other transportation costs to delivery points. Under
financial instrument contracts, the Company may also be at risk for basis
differential, which is the difference in the quoted financial price for contract
settlement and the actual price received at the physical point of delivery.
Substantial variations between the assumptions and estimates used by the Company
and actual results experienced could materially adversely affect the Company's
anticipated profit margins and its ability to manage the risk associated with
fluctuations in oil and gas prices. In addition, hedging contracts are subject
to the risk that the other party may prove unable or unwilling to perform its
obligations under such contracts. Any significant nonperformance could have a
material adverse financial effect on the Company. Furthermore, hedging contracts
limit the benefits the Company would realize if actual prices rise above the
contract prices.
REPLACEMENT OF RESERVES
Basin's future success depends upon its ability to find, develop and/or
acquire additional oil and gas reserves at prices that permit profitable
operations. Except to the extent that Basin conducts successful development,
exploitation or exploration activities or acquires properties containing proved
reserves, the proved reserves of Basin will decline. The rate of decline depends
upon reservoir characteristics and varies from the steep decline rate
characteristic of Gulf of Mexico reservoirs, where Basin has most of its
production, to the relatively slow decline rate characteristic of the long-lived
fields in the Rocky Mountain region, where the Company's other properties are
located. The market for acquiring proved reserves is extremely competitive, and
the Company may not be able to buy reserves for development and exploitation at
prices it considers to be reasonable or within its budgets. The cost of
drilling, completing and operating wells may vary significantly from initial
estimates. Basin's drilling operations may be unsuccessful or may be curtailed,
delayed or canceled as a result of numerous factors not within Basin's control,
including but
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<PAGE>
not limited to title problems, weather conditions, compliance with governmental
requirements, shortage of capital, mechanical difficulties and shortages or
delays in the delivery of drilling rigs or other equipment. Accordingly, there
can be no assurance that Basin's acquisition, development, exploitation and
exploration activities will result in reserves added at acceptable costs.
ACQUISITION RISKS
Acquisitions of producing oil and gas properties have been a key element of
Basin's success, and Basin will continue to seek acquisitions in the future.
Even though Basin performs a review of the properties in connection with its
acquisitions which it believes is consistent with industry practices, such
reviews are inherently incomplete, and the evaluations resulting therefrom are
necessarily inexact and uncertain. It is generally not feasible to review in
depth every property and all records in connection with an acquisition of many
properties, particularly when the seller does not operate the property.
Ordinarily Basin will focus its due diligence efforts on the higher valued
properties and will spot-check the remainder. However, even an in-depth review
of properties and records may not necessarily reveal existing or potential
problems nor will it permit a buyer to become familiar enough with the
properties to assess fully their deficiencies and capabilities. Inspections may
not be performed on every well, and environmental problems, such as groundwater
contamination, are not necessarily observable even when an inspection is
undertaken. Contractual indemnities may not be obtainable, and the Company may
be required to assume the risk of the physical condition of the properties in
addition to the risk that the properties may not perform in accordance with the
Company's expectations.
EXPLORATION RISKS
With the sale of its D-J Basin properties in 1996, and its initiation of
exploration activities in the Gulf of Mexico, the Company currently is spending
a large portion of its capital budget on exploration. Exploration activities
involve substantially more risk than development or exploitation activities.
Although the Company believes that its use of 3-D seismic data and other
advanced technologies should increase the probability of success of its
exploratory wells and should reduce average finding costs through elimination of
prospects that might otherwise be drilled solely on the basis of 2-D seismic
data and other traditional methods, exploratory drilling remains a speculative
activity. Even when fully utilized and properly interpreted, 3-D seismic data
and visualization techniques only assist geoscientists in identifying subsurface
structures and hydrocarbon indicators and do not conclusively allow the
interpreter to know if hydrocarbons will in fact be present in such structures.
In addition, the use of 3-D seismic data and such technologies requires greater
predrilling expenditures than traditional drilling strategies and the Company
could incur losses as a result of such expenditures. Failure of the Company's
exploration activities would have a material adverse effect on the Company's
future results of operations and financial condition. The Company had conducted
no previous operations in the Gulf of Mexico prior to the opening of its
regional office in late 1995 in Houston, Texas. This operating area is highly
competitive and the Company's success in its activities there will depend on its
ability to attract and retain geoscientists and other professional staff with
extensive experience operating in the area. The Company's Houston office
currently has a staff that includes seven geoscientists and petroleum engineers
plus 3 engineering consultants, all of whom are experienced in Gulf Coast
operations. Loss of these experienced personnel could have a material adverse
impact on the Company's ability to compete in this area.
FUTURE CAPITAL REQUIREMENTS
The Company will require substantial additional capital to further develop
and explore its properties and to acquire additional properties. Cash flows from
operations, to the extent available, will be used to fund these expenditures.
The Company may seek additional capital from traditional reserve base
borrowings, equity and debt offerings, joint ventures, and/or production payment
financing. The Company's ability to access additional capital will depend
significantly on its continued success in exploring for and developing its
reserves and the status of the capital markets at the time such capital is
sought. Accordingly,
5
<PAGE>
there can be no assurance that capital will be available to the Company from any
source or that, if available, it will be on terms acceptable to the Company.
Should sufficient capital not be available, the development and exploration of
the Company's properties could be delayed and, accordingly, the implementation
of the Company's business strategy would be adversely affected.
MARKETING OF PRODUCTION; SEASONALITY
The marketability of Basin's production depends upon the availability and
capacity of gathering systems and pipelines, the effects of federal and state
regulation of such production and transportation, general economic conditions,
supply of and demand for oil and natural gas, all of which could adversely
affect Basin's ability to market its production. Demand for natural gas is
highly seasonal, with demand generally higher in the colder winter months and in
the hot summer months. As a result, the price 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.
CONCENTRATION OF VALUE
As of the date of this Prospectus, a significant portion of Basin's
production is concentrated in two wells on one platform in the Gulf of Mexico.
If mechanical problems, storms, or other events that caused curtailment or
cessation of such production were to occur, Basin's cash flow would be
materially adversely affected. The Company will remain vulnerable to a
disproportionate impact of delays or interruptions of production from these
wells until it develops a more diversified production base including additional
properties.
ESTIMATES OF RESERVES AND RELATED DATA
Numerous uncertainties are 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 in this Prospectus or incorporated herein by reference
represents only estimates based on available geological, geophysical, production
and engineering data, the extent, quality and reliability of which vary. Oil and
gas reserve engineering is a subjective process of estimating accumulations of
oil and gas that cannot be measured in an exact manner, and estimates of other
engineers might differ materially from those shown. The accuracy of any reserve
estimate is a function of the quality and quantity of available data,
engineering and geological interpretation and judgment. In addition, the
estimates of future net cash flow from proved reserves of the Company and the
present value thereof are based upon certain assumptions about future production
levels, prices, costs and participation, if any, by third parties in the
development of the Company's reserves that may not prove correct over time, for
reasons which may or may not be under the control of or known to the Company.
Any significant variance from these assumptions could materially affect the
quantity and value of the Company's reserves as compared to the estimates
contained in this Prospectus.
FLUCTUATIONS IN QUARTERLY RESULTS
Basin's quarterly results of operations may fluctuate significantly as a
result of variations in oil and gas prices and variations in the Company's
drilling activities. Drilling activities can be affected by a number of factors
including the need to utilize capital for new acquisitions, availability of
permits for drilling or recompletions, weather, seasonal restrictions (such as
growing crops and winter game restrictions), governmental regulations and
available cash flow.
OPERATING HAZARDS
The oil and gas business involves a variety of operating risks, including
the risk of fire, explosion, blow-out, pipe failure, casing collapse, stuck
tools, abnormally pressured formations and environmental hazards
6
<PAGE>
such as oil spills, gas leaks, pipeline ruptures and discharges of toxic gases,
the occurrence of any of which could result in substantial losses to Basin due
to injury and loss of life, loss of or damage to wellbores and/ or drilling or
production equipment, costs of overcoming downhole problems, severe damage to
and destruction of property, natural resources and equipment, pollution and
other environmental damage, clean-up responsibilities, regulatory investigation
and penalties and suspension of operations. Gathering systems and processing
facilities are subject to many of the same hazards and any significant problems
related to those facilities could adversely affect Basin's ability to market its
production. Moreover, offshore operations are subject to a variety of operating
risks peculiar to the marine environment, such as hurricanes or other adverse
weather conditions. Basin maintains insurance against some, but not all,
potential risks; however, there can be no assurance that such insurance will be
adequate to cover any losses or exposure for liability. Insurance may not cover
downhole operating risks, such as the costs of retrieving stuck equipment.
Furthermore, Basin cannot predict whether insurance will continue to be
available at premium levels that justify its purchase or whether insurance will
be available at all to cover the risks faced by the Company.
ENVIRONMENTAL REGULATION
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. 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 regulation is likely to continue. Offshore
operations are subject to more extensive governmental regulation, including
regulation that may, in certain circumstances, impose absolute liability for
environmental damage and allow interruption or termination of business
activities by government authorities based on environmental or other
considerations. The Oil Pollution Act of 1990 (the "OPA") also requires proof of
financial responsibility to cover costs of potential oil spills; the amount of
such required coverage ranges from $35 million to $150 million based on federal
risk assessment. From time to time, legislation has been introduced in Congress
which would reclassify oil and gas production wastes as "hazardous waste" under
the Resource Conservation and Recovery Act. If such legislation were to pass, it
could have a significant adverse impact on the operating costs of Basin, as well
as the oil and gas industry in general. Initiatives regulating the disposal of
exploration and production 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 the Company.
GOVERNMENTAL REGULATION
Development, production and sale of oil and gas are subject to extensive
federal, state and local governmental regulation which may be changed from time
to time in response to economic or political conditions. Matters subject to
regulation include, but are not limited to, permits for drilling operations,
drilling, plugging and reclamation bonds, operational practices and reporting,
the spacing of wells, unitization and pooling of properties, taxation and
environmental protection. The Minerals Management Service of the United States
Department of the Interior ("MMS") has proposed regulations for valuation of
crude oil and natural gas produced from federal leases, including offshore
leases, that could require payment of royalties on the basis of indices or
benchmarks that may not reflect actual prices received by the Company for its
production. The Federal Energy Regulatory Commission has promulgated major
regulatory initiatives over the past several years which have had a significant
impact on natural gas pricing and natural gas pipeline operations, services and
rates. Those changes have significantly altered the marketing of natural gas.
Although the purpose of these changes is generally to enhance competition in
natural gas marketing, the effect of these changes on the Company's ability to
market its gas at reasonable
7
<PAGE>
prices from any given property is uncertain. From time to time, regulatory
agencies have imposed price controls and limitations on production by
restricting the rate of flow of oil and gas wells below actual production
capacity in order to conserve supplies of oil and gas. Under the Outer
Continental Shelf Lands Act ("OCSLA") the MMS regulates development and
production of oil and gas in federal waters in the Gulf of Mexico and may
suspend or terminate operations for violation of MMS rules. Any such suspension
or termination could materially and adversely affect the Company's financial
condition and operations. There are many legislative proposals pending in
Congress and in the legislatures of various states that, if enacted, might
significantly affect the oil and gas industry. Basin is not able to predict what
will be enacted and thus what effect, if any, such proposals would have on
Basin.
COMPETITION
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.
PRINCIPAL STOCKHOLDER
Basin's principal stockholder, Michael S. Smith, together with members of
his immediate family and trustees for their benefit, beneficially own
approximately 30% of Basin's outstanding shares. As a result, Mr. Smith is in a
position to substantially influence the outcome of stockholder votes on the
election of directors and other matters. In addition, if Mr. Smith were to sell
a significant number of his shares, the prevailing market price of the Common
Stock could be adversely affected.
DEPENDENCE ON KEY PERSONNEL
Basin depends to a large extent on the services of its founder and CEO,
Michael Smith and certain other senior management personnel. The loss of the
services of Mr. Smith or other key personnel could have a potential adverse
effect on Basin's operations.
ANTI-TAKEOVER PROVISIONS
Basin's Restated Certificate of Incorporation and Bylaws and the provisions
of the Delaware General Corporation Law make it more difficult to change control
of Basin and replace incumbent management. The Company adopted a Stockholders'
Rights Plan in 1996, pursuant to which holders of Common Stock of the Company
received rights which are exercisable if a person or group of affiliated persons
acquires 15% of the Company's outstanding Common Stock or commences a tender or
exchange offer, the consummation of which would result in ownership of 15% or
more of the Company's outstanding Common Stock. See "Description of Capital
Stock--Stockholders' Rights Plan." In addition, the Company has entered into
agreements with certain of its executive officers which would require additional
payments by the Company if such officers' employment were terminated upon a
change of control.
8
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THE COMPANY
GENERAL
Basin Exploration, Inc. ("Basin" or the "Company") is an independent oil and
gas exploration and production company operating in the United States. The
Company's business objective is to efficiently increase its proved oil and gas
reserves in order to grow production, cash flow, and earnings per share. The
Company seeks to accomplish this by exploring for new oil and gas reserves and
acquiring proved properties with exploitation or development potential,
utilizing advanced technologies.
The Company currently conducts exploration activities exclusively in the
shallow waters of the Gulf of Mexico, offshore Louisiana and Texas. Basin seeks
acquisition opportunities both in the vicinity of the Company's exploration
activities offshore and in certain geographic areas onshore where the Company's
staff has had extensive experience, including the Rocky Mountains and onshore
Gulf Coast areas.
Basin's reserves are located primarily in the Gulf of Mexico and in the
Powder River and Green River Basins in Wyoming. At December 31, 1996, the
Company's estimated proved reserves totaled approximately 7.9 MMBbl and 29.7 Bcf
of natural gas, or 76.9 Bcfe. Most of Basin's proved oil and gas reserves are
attributable to Company-operated properties. A significant portion of Basin's
reserves at the beginning of 1996 were located in the Denver-Julesburg ("D-J")
Basin in eastern Colorado, but such reserves were sold in 1996 to provide funds
for other operations, including initiation of operations in the Gulf of Mexico.
Since commencing operations in the Gulf of Mexico in 1996, the Company has
participated in drilling ten wells, of which five have been or are expected to
be completed as producers. The Company has operated all but one of these wells,
with an average working interest at the time of drilling of approximately 51%.
Five of the ten wells drilled to date have been drilled since July 1, 1997,
reflecting a recent acceleration in activity after a start-up period during
which the Company assembled its initial prospect inventory. As of the date of
this Prospectus, the Company has assembled a Gulf of Mexico leasehold inventory
of 96,421 gross acres, comprising 63,248 net acres, with more than 20 identified
potential exploration prospects, all of which are supported by the Company's
interpretations of three-dimensional ("3-D") seismic data. In order to reduce
the risks and costs for acreage, drilling and completion operations, the Company
uses 3-D seismic and computer-aided exploration and exploitation technology in
virtually all of its activities in the Gulf of Mexico. The Company has also
closed acquisitions of Gulf of Mexico proved properties totaling more than $18
million in 1997 through the date of this Prospectus.
Two of the Gulf of Mexico wells that the Company has completed, both located
on Eugene Island Block 65, commenced production in August 1997 and now account
for a substantial portion of the Company's total oil and gas production. The
three other drilled wells that the Company anticipates will commence production,
plus an additional Gulf of Mexico well in which the Company acquired an interest
after it was drilled and completed, are temporarily suspended pending additional
development. Three of these wells, one each on East Cameron Block 378, Eugene
Island Block 83, and West Cameron Block 56, are expected to commence production
shortly before or during the first quarter of 1998.
The Company's onshore oil and gas assets are comprised of properties that
generally have a relatively stable, long-lived production profile. The Company
has identified potential for additional drilling, well deepenings, or secondary
recovery on several of the more valuable properties. The Company intends to
continue to exploit, and to pursue acquisitions to expand, this asset base.
The Company currently has a capital budget established for 1997 of
approximately $60 million, allocated approximately equally to exploration
activities, development, and acquisitions that have already been consummated.
This budget could be increased for additional acquisitions or for development of
additional exploratory discoveries. The 1997 capital budget represents a
significant increase from capital expenditures on oil and gas properties in 1996
and 1995 of approximately $23 million and $16 million, respectively.
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HISTORY
Basin 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 D-J Basin. Such
operations were expanded into other areas within the Rocky Mountain region in
1992, and the Company initiated Rocky Mountain exploration activities in 1993.
By December 31, 1994, the Company's estimated proved oil and gas reserves had
grown to 247.2 Bcfe, of which 169.2 Bcfe, or 68.4%, were located in the D-J
Basin.
From 1992 through 1994, the D-J Basin was one of the most active drilling
areas in the United States and the Company was one of the more active and
successful operators in the area. As the basin became increasingly exploited,
however, it was the Company's assessment and experience that the number and
quality of development projects in the area significantly diminished.
During 1995, the Company's capital expenditures on oil and gas properties
declined to $16 million, from $67 million the year before, and its estimated
proved oil and gas reserves declined to 207.1 Bcfe at year-end. Principal
factors contributing to these reductions included: (i) a smaller and
lower-quality inventory of D-J Basin exploitation projects; (ii) insufficient
success in identifying acquisition opportunities and viable exploration plays in
the Company's other Rocky Mountain focus areas; and (iii) liquidity constraints
caused largely by the Company's higher debt levels.
In direct response to these developments, the Company implemented a
significant redirection of its business strategy and operations between
late-1995 and mid-1996, including: (i) the addition of new financial, technical
and business development members to its senior management; (ii) the sale of the
Company's D-J Basin assets, including approximately 70% of the Company's
estimated proved reserves, for $123.5 million; (iii) establishment of a
Houston-based Gulf of Mexico exploration team through the hiring of senior
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.
Since the redirection of its business, the Company has significantly
increased its proved reserves and production base through Gulf of Mexico
drilling activity and acquisitions, and it has established a sizable inventory
of Gulf of Mexico leaseholds and prospects for future exploratory drilling.
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USE OF PROCEEDS
Unless a Prospectus Supplement indicates otherwise, the net proceeds to be
received by the Company from the sale of the Securities will be used for
repayment of indebtedness, to finance the Company's operations, for the
continued development of its oil and gas properties and for other general
corporate purposes. Pending such application, such net proceeds may be invested
in short-term marketable securities.
RATIO OF EARNINGS TO FIXED CHARGES
The ratio of earnings to fixed charges for the Company was as follows for
the years ended December 31, 1996, 1995, 1994, 1993 and 1992:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------
1996 1995 1994 1993
----- ----- ----- -----
<S> <C> <C> <C> <C>
Ratio of earnings to fixed charges (unaudited)....................... 9.6 (a) 2.6 3.5
<CAPTION>
1992
-----
<S> <C>
Ratio of earnings to fixed charges (unaudited)....................... 3.2
</TABLE>
- ------------------------
(a) Earnings did not cover fixed charges in 1995 by $27.3 million.
As used in the above calculations, "earnings" means earnings before income
taxes and fixed charges, and "fixed charges" means interest on all indebtedness,
that portion of rental expense that management believes to be representative of
interest expense and capitalized interest.
DESCRIPTION OF DEBT SECURITIES
Debt Securities may be issued from time to time in one or more series by the
Company. The Debt Securities will constitute either indebtedness designated as
Senior Indebtedness ("Senior Debt Securities"), indebtedness designated as
Senior Subordinated Indebtedness ("Senior Subordinated Debt Securities") or
indebtedness designated as Subordinated Indebtedness ("Subordinated Debt
Securities"). The particular terms of each series of Debt Securities offered by
a particular Prospectus Supplement will be described therein. Senior Debt
Securities, Senior Subordinated Debt Securities and Subordinated Debt Securities
will each be issued under a separate indenture (individually an "Indenture" and
collectively the "Indentures") to be entered into prior to the issuance of such
Debt Securities. The Indentures will be substantially identical, except for
provisions relating to subordination. See "Subordination of Senior Subordinated
Debt Securities and Subordinated Debt Securities." A copy of the form of the
Indenture is filed as an Exhibit to the Registration Statement of which this
Prospectus is a part. There will be a separate Trustee (individually a "Trustee"
and collectively the "Trustees") under each Indenture. Information regarding the
Trustee under an Indenture will be included in any Prospectus Supplement
relating to the Debt Securities issued thereunder.
The following discussion includes a summary description of the material
terms of the Indentures, other than terms which are specific to a particular
series of Debt Securities and which will be described in the Prospectus
Supplement relating to such series. The following summaries do not purport to be
complete and are subject to, and are qualified in their entirety by reference
to, all of the provisions of the Indentures, including the definitions therein
of certain terms capitalized in this Prospectus. Wherever particular Sections,
Articles or defined terms of the Indentures are referred to herein or in a
Prospectus Supplement, such Sections, Articles or defined terms are incorporated
herein or therein by reference.
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GENERAL
The Debt Securities will be general unsecured obligations of the Company.
The Indentures do not limit the aggregate amount of Debt Securities which may be
issued thereunder, and Debt Securities may be issued thereunder from time to
time in separate series up to the aggregate amount from time to time authorized
for each series. Debt Securities of a series may be issuable in registered form
without coupons ("Registered Debt Securities"), in bearer form with or without
coupons attached ("Bearer Debt Securities") or in the form of one or more global
Securities in registered or bearer form (each, a "Global Security"). Bearer Debt
Securities, if any, will be offered only to non-United States persons and to
offices located outside the United States of certain United States financial
institutions.
The applicable Prospectus Supplement or Prospectus Supplements will describe
the following terms of the series of Debt Securities in respect of which this
Prospectus is being delivered: (1) the title of such Debt Securities; (2) any
limit on the aggregate principal amount of such Debt Securities; (3) whether
such Debt Securities will be issued as Registered Debt Securities, Bearer Debt
Securities or any combination thereof, and any limitation on issuance of such
Bearer Debt Securities and any provisions regarding the transfer or exchange of
such Bearer Debt Securities, including exchange for Registered Debt Securities
of the same series; (4) whether any of such Debt Securities are to be issuable
in permanent global form and, if so, the terms and conditions, if any, upon
which interests in such Debt Securities in global form may be exchanged, in
whole or in part, for the individual Debt Securities represented thereby; (5)
the person to whom any interest on any Debt Security of the series shall be
payable, if other than the person in whose name the Debt Security is registered
on the Regular Record Date; (6) the date or dates on which such Debt Securities
will mature; (7) the rate or rates of interest, if any, or the method of
calculation thereof, which such Debt Securities will bear, and the basis upon
which interest will be calculated if other than that of a 360-day year of twelve
30-day months; (8) the date or dates from which any such interest will accrue,
the Interest Payment Dates on which any such interest on such Debt Securities
will be payable, the Regular Record Date for any interest payable on any
Interest Payment Date and any provision for the deferral of interest payments;
(9) whether any such interest will be payable in cash, through the issuance of
additional Debt Securities, through the issuance of Common Stock, through some
combination of cash and additional Debt Securities or through some combination
of cash and Common Stock; (10) the place or places where the principal of,
premium, if any, and interest on such Debt Securities will be payable; (11) the
period or periods within which, the events upon the occurrence of which, and the
price or prices at which, such Debt Securities may, pursuant to any optional or
mandatory provisions, be redeemed or purchased, in whole or in part, by the
Company and any terms and conditions relevant thereto; (12) the obligations of
the Company, if any, to redeem or repurchase such Debt Securities pursuant to
any sinking fund or analogous provisions or at the option of the Holders
thereof; (13) the denominations in which any such Debt Securities will be
issuable, if other than denominations of US $1,000 and any integral multiple
thereof; (14) the units of payment of principal of, premium, if any, and
interest on such Debt Securities if other than US dollars, which units may
consist of currency, currencies, currency unit or units, or securities; (15) any
index or formula to be used to determine the amount of payments of principal,
premium, if any, and interest on such Debt Securities, and any commodities,
currencies, currency units or indices, or value, rate or price, relevant to such
determination; (16) if the principal of, premium, if any, or interest on such
Debt Securities is to be payable, at the election of the Company or a Holder
thereof, in one or more currencies or currency units other than that or those in
which such Debt Securities are stated to be payable, the currencies or currency
units in which payment of the principal of, premium, if any, and interest on
such Debt Securities as to which election is made shall be payable, and the
periods within which and the terms and conditions upon which such election is to
be made; (17) if other than the principal amount thereof, the portion of the
principal amount of such Debt Securities of the series which will be payable
upon acceleration of the Maturity thereof; (18) whether such Debt Securities are
subordinate in right of payment to any Senior Indebtedness of the Company and,
if so, the terms and conditions of such subordination and the aggregate
principal amount of such Senior Indebtedness outstanding as of a recent date;
(19) any covenants to which the Company may be subject with respect to such Debt
Securities;
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(20) the applicability of the provisions described under "Defeasance" below;
(21) the terms and conditions, if any, pursuant to which such Debt Securities
are convertible into or exchangeable for Common Stock or other securities; (22)
if the principle amount payable at the Stated Maturity of the Debt Securities is
not determinable upon original issuance or at any time prior to Maturity, the
amount that is deemed to be the principal amount outstanding at any time; (23)
the terms of any guarantee of the payment of principal and interest on the Debt
Securities; (24) any additions, deletions or changes in the Events of Default
with respect to the Debt Securities and (25) any other terms of such Debt
Securities.
Debt Securities may be issued at a discount from their principal amount.
United States federal income tax considerations and other special considerations
applicable to any such Original Issue Discount Securities will be described in
the applicable Prospectus Supplement.
If the purchase price of any series of Debt Securities is denominated in a
foreign currency or currencies or a foreign currency unit or units or if the
principal of, premium, if any, and interest on any series of Debt Securities are
payable in a foreign currency or currencies, a foreign currency unit or units or
in securities, the restrictions, elections, general tax considerations, specific
terms and other information with respect to such series of Debt Securities will
be set forth in the applicable Prospectus Supplement.
Debt Securities may be issued from time to time with payment terms which are
calculated by reference to the value, rate or price of one or more commodities,
currencies, currency units or indices. Holders of such Debt Securities may
receive a principal amount (including premium, if any) on any principal payment
date, or a payment of interest on any interest payment date, that is greater
than or less than the amount of principal (including premium, if any) or
interest otherwise payable on such dates, depending upon the value, rate or
price on the applicable dates of the applicable currency, currency unit,
commodity or index. Information as to the methods for determining the amount of
principal, premium, if any, or interest payable on any date, the currencies,
currency units, commodities or indices to which the amount payable on such date
is linked and any additional tax considerations will be set forth in the
applicable Prospectus Supplement.
SENIOR DEBT SECURITIES
The Senior Debt Securities will rank pari passu with all other unsecured and
unsubordinated debt of the Company and senior to the Senior Subordinated Debt
Securities and Subordinated Debt Securities.
SUBORDINATION OF SENIOR SUBORDINATED DEBT SECURITIES, SUBORDINATED DEBT
SECURITIES AND GUARANTEES
The payment of the principal of, premium, if any, and interest on the Senior
Subordinated Debt Securities and the Subordinated Debt Securities will, to the
extent set forth in the respective Indentures governing such Senior Subordinated
Debt Securities and Subordinated Debt Securities, be subordinated in right of
payment to the prior payment in full of all Senior Indebtedness. Upon any
payment or distribution of assets to creditors upon any liquidation,
dissolution, winding up, reorganization, assignment for the benefit of
creditors, marshalling of assets or any bankruptcy, insolvency or similar
proceedings of the Company, the holders of all Senior Indebtedness will be
entitled to receive payment in full of all amounts due or to become due thereon
before the Holders of the Senior Subordinated Debt Securities or the
Subordinated Debt Securities will be entitled to receive any payment in respect
of the principal of, premium, if any, or interest on such Senior Subordinated
Debt Securities or Subordinated Debt Securities, as the case may be. In the
event of the acceleration of the maturity of any Senior Subordinated Debt
Securities or Subordinated Debt Securities, the holders of all Senior
Indebtedness will be entitled to receive payment in full of all amounts due or
to become due thereon before the Holders of the Senior Subordinated Debt
Securities or Subordinated Debt Securities, as the case may be, will be entitled
to receive any payment upon the principal of, premium, if any, or interest on
such Senior Subordinated Debt Securities or Subordinated Debt Securities, as the
case may be. No payments on account of principal, premium, if any, or interest
in respect of the Senior Subordinated Debt Securities or Subordinated Debt
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Securities may be made if there shall have occurred and be continuing a default
in the payment of principal of (or premium, if any) or interest on any Senior
Indebtedness beyond any applicable grace period, or a default with respect to
any Senior Indebtedness permitting the holders thereof to accelerate the
maturity thereof, or if any judicial proceedings shall be pending with respect
to any such default. For purposes of the subordination provisions, the payment,
issuance or delivery of cash, property or securities (other than stock, and
certain subordinated securities, of the Company) upon conversion, redemption or
otherwise of a Senior Subordinated Debt Security or Subordinated Debt Security
will be deemed to constitute payment on account of the principal of such Senior
Subordinated Debt Security or Subordinated Debt Security, as the case may be.
By reason of such provisions, in the event of insolvency, holders of Senior
Subordinated Debt Securities and Subordinated Debt Securities may recover less,
ratably, than holders of Senior Indebtedness with respect thereto.
The term "Senior Indebtedness," means the obligations of the Company with
respect to (i) Indebtedness of the Company under the Bank Credit Facility and
any renewal, refunding, refinancing, replacement or extension thereof and (ii)
any other Indebtedness of the Company (other than the Securities), whether
outstanding on the date of this Indenture or thereafter created, incurred or
assumed, and any renewal, refunding, refinancing, replacement or extension
thereof, unless, in the case of any particular Indebtedness, the instrument
creating or evidencing the same or pursuant to which the same is outstanding
expressly provides that such Indebtedness shall not be senior in right of
payment to the Securities or that such indebtedness is PARI PASSU with or junior
to the Securities. Notwithstanding the foregoing, Senior Indebtedness shall not
include (i) indebtedness of the Company to a subsidiary of the Company, (ii)
amounts owed for goods, materials or services purchased in the ordinary course
of business, (iii) indebtedness incurred in violation of this Indenture, (iv)
amounts payable or any other Indebtedness to employees of the Company or any
Subsidiary of the Company, (v) any liability for Federal, state, local or other
taxes owed or owing by the Company, (vi) any indebtedness of the Company that,
when incurred and without regard to any election under Section 1111(b) of the
United States Bankruptcy Code, was without recourse to the Company, and (vii)
indebtedness evidenced by Senior Subordinated Debt Securities.
If this Prospectus is being delivered in connection with a series of Senior
Subordinated Debt Securities or Subordinated Debt Securities, the accompanying
Prospectus Supplement or the information incorporated herein by reference will
set forth the approximate amount of Senior Indebtedness outstanding as of the
end of the Company's most recent fiscal quarter.
FORM, EXCHANGE, REGISTRATION, CONVERSION, TRANSFER AND PAYMENT
Debt Securities are issuable in definitive form as Registered Debt
Securities, as Bearer Debt Securities or both. Unless otherwise indicated in an
applicable Prospectus Supplement, Bearer Debt Securities will have interest
coupons attached. Debt Securities are also issuable in temporary or permanent
global form.
Registered Debt Securities of any series (other than a Global Security) will
be exchangeable for other Registered Debt Securities of the same series and of a
like aggregate principal amount and tenor of different authorized denominations.
In addition, with respect to any series of Bearer Debt Securities, at the option
of the holder, subject to the terms of the Indenture, such Bearer Debt
Securities (with all unmatured coupons, except as provided below, and all
matured coupons in default) will be exchangeable into Registered Debt Securities
of the same series of any authorized denominations and of a like aggregate
principal amount and tenor. Bearer Debt Securities surrendered in exchange for
Registered Debt Securities between a Regular Record Date or a Special Record
Date and the relevant date for payment of interest shall be surrendered without
the coupon relating to such date for payment of interest, and interest accrued
as of such date will not be payable in respect of the Registered Debt Security
issued in exchange
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for such Bearer Debt Security, but will be payable only to the holder of such
coupon when due in accordance with the terms of the Indenture.
In connection with its sale during the restricted period (as defined below),
no Bearer Debt Security (including a Debt Security in permanent global form that
is either a Bearer Debt Security or exchangeable for Bearer Debt Securities)
shall be mailed or otherwise delivered to any location in the United States (as
defined under "--Limitations on Issuance of Bearer Debt Securities") and a
Bearer Debt Security may be delivered outside the United States in definitive
form in connection with its original issuance only if prior to delivery the
person entitled to receive such Bearer Debt Security furnishes written
certification, in the form required by the Indenture, to the effect that such
Bearer Debt Security is owned by: (a) a person (purchasing for its own account)
who is not a United States person (as defined under "--Limitations on Issuance
of Bearer Debt Securities"); (b) a United States person who (i) is a foreign
branch of a United States financial institution purchasing for its own account
or for resale or (ii) acquired such Bearer Debt Security through the foreign
branch of a United States financial institution and who for purposes of the
certification holds such Bearer Debt Security through such financial institution
on the date of certification and, in either case, such United States financial
institution certifies to the Company or the distributor selling the Bearer Debt
Security within a reasonable time stating that it agrees to comply with the
requirements of Section 165(j)(3)(A), (B) or (C) of the United States Internal
Revenue Code of 1986, as amended (the "Code"), and the regulations thereunder,
or (c) a United States or foreign financial institution for purposes of resale
within the "restricted period" as defined in United States Treasury Regulations
Section 1.163-5(c)(2)(i)(D)(7). A financial institution described in clause (c)
of the preceding sentence (whether or not also described in clauses (a) and (b))
must certify that it has not acquired the Bearer Debt Security for purpose of
resale, directly or indirectly, to a United States person or to a person within
the United States or its possessions. In the case of a Bearer Debt Security in
permanent global form, such certification must be given in connection with
notation of a beneficial owner's interest therein in connection with the
original issuance of such Debt Security or upon exchange of a portion of a
temporary global Debt Security.
Debt Securities may be presented for exchange as provided above, and
Registered Debt Securities may be presented for registration of transfer (with
the form of transfer endorsed thereon duly executed), at the office or agency of
the Company maintained for such purposes and at any other office or agency
maintained for such purpose with respect to any series of Debt Securities and
referred to in the applicable Prospectus Supplement, without a service charge
and upon payment of any taxes and other governmental charges as described in the
Indenture. Such transfer or exchange will be effected upon the Company or its
agent, as the case may be, being satisfied with the documents of title and
identity of the person making the request.
The Company shall not be required to (i) issue, register the transfer of or
exchange Debt Securities of any series during a period of 15 days prior to the
mailing of a notice of redemption of Debt Securities of that series; or (ii)
register the transfer of or exchange any Debt Security, or portion thereof,
called for redemption, except that any Bearer Debt Security exchangeable for a
Registered Debt Security of that series may be so exchanged during the period
preceding the redemption date therefor which is simultaneously surrendered for
redemption.
PAYMENT AND PAYING AGENTS
Unless otherwise indicated in the applicable Prospectus Supplement, payment
of principal of (and premium, if any) and interest on Bearer Debt Securities
will be payable, subject to any applicable laws and regulations, in the
designated currency or currency unit, at the offices of such Paying Agents
("Paying Agents") outside the United States as the Company may designate from
time to time, at the option of the holder, by check or by transfer to an account
maintained by the payee with a bank located outside the United States; provided,
however, that the written certification described above under "--Form, Exchange,
Registration, Conversion, Transfer and Payment" has been delivered prior to the
first actual payment of
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interest. Unless otherwise indicated in the applicable Prospectus Supplement,
payment of interest on Bearer Debt Securities on any Interest Payment Date will
be made only against surrender to the Paying Agent of the coupon relating to
such Interest Payment Date. No payment with respect to any Bearer Debt Security
will be made at any office or agency of the Company in the United States or by
check mailed to any address in the United States or by transfer to any account
maintained with a bank located in the United States, nor shall any payments be
made in respect of Bearer Debt Securities upon presentation to the Company or
its designated Paying Agents within the United States. Notwithstanding the
foregoing, payments of principal of (and premium, if any) and interest on Bearer
Debt Securities denominated and payable in US dollars will be made at the office
of the Company's Paying Agent in the United States, if (but only if) payment of
the full amount thereof in US dollars at all offices or agencies outside the
United States is illegal or effectively precluded by exchange controls or other
similar restrictions.
Unless otherwise indicated in the applicable Prospectus Supplement, payment
of principal of (and premium, if any) and interest on Registered Debt Securities
will be made in the designated currency or currency unit at the office of such
Paying Agent or Paying Agents as the Company may designate from time to time,
except that at the option of the Company payment of any interest may be made by
check mailed to the address of the person entitled thereto as such address shall
appear in the Security Register. Unless otherwise indicated in an applicable
Prospectus Supplement, payment of any installment of interest on Registered Debt
Securities will be made to the person in whose name such Registered Debt
Security is registered at the close of business on the Regular Record Date for
such interest.
Unless otherwise indicated in the applicable Prospectus Supplement, the
Corporate Trust Office of the Trustee will be designated as a Paying Agent for
the Trustee for payments with respect to Debt Securities which are issuable
solely as Registered Debt Securities, and the Company will maintain a Paying
Agent outside the United States for payments with respect to Debt Securities
(subject to limitations described above in the case of Bearer Debt Securities)
which are issued solely as Bearer Debt Securities, or as both Registered Debt
Securities and Bearer Debt Securities. Any Paying Agents outside the United
States and any other Paying Agents in the United States initially designated by
the Company for the Debt Securities will be named in an applicable Prospectus
Supplement. The Company may at any time designate additional Paying Agents or
rescind the designation of any Paying Agent or approve a change in the office
through which any Paying Agent acts, except that, if Debt Securities of a series
are issued solely as Registered Debt Securities, the Company will be required to
maintain a Paying Agent in each Place of Payment for such series and, if Debt
Securities of a series are issued as Bearer Securities, the Company will be
required to maintain (i) a Paying Agent in the United States for principal
payments with respect to any Registered Debt Securities of the series (and for
payments with respect to Bearer Debt Securities of the series in the
circumstances described above, but not otherwise), and (ii) a Paying Agent in a
Place of Payment located outside the United States where Securities of such
series and any coupons appertaining thereto may be presented and surrendered for
payment.
All monies paid by the Company to a Paying Agent for the payment of
principal of and any premium or interest on any Debt Security which remain
unclaimed at the end of two years after such principal, premium or interest
shall have become due and payable will (subject to applicable escheat laws) be
repaid to the Company and the holder of such Debt Security or any coupon will
thereafter look only to the Company for payment thereof.
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TEMPORARY GLOBAL SECURITIES
If so specified in the applicable Prospectus Supplement, all or any portion
of the Debt Securities of a series which are issuable as Bearer Debt Securities
will initially be represented by one or more temporary global Debt Securities,
without interest coupons, to be deposited with a common depository in London for
the Euroclear System ("Euroclear") and CEDEL S.A. ("CEDEL") for credit to the
designated accounts. On and after the date determined as provided in any such
temporary global Debt Security and described in the applicable Prospectus
Supplement, each such temporary global Debt Security will be exchangeable for
definitive Bearer Debt Securities, definitive Registered Debt Securities or all
or a portion of a permanent global security, or any combination thereof, as
specified in the applicable Prospectus Supplement, but, unless otherwise
specified in the applicable Prospectus Supplement, only upon written
certification in the form and to the effect described under "--Form, Exchange,
Registration, Conversion, Transfer and Payment." No Bearer Debt Security
delivered in exchange for a portion of a temporary global Debt Security will be
mailed or otherwise delivered to any location in the United States in connection
with such exchange.
Unless otherwise specified in the applicable Prospectus Supplement, interest
in respect of any portion of a temporary global Debt Security payable in respect
of an Interest Payment Date occurring prior to the issuance of definitive Debt
Securities or a permanent global Debt Security will be paid to each of Euroclear
and CEDEL with respect to the portion of the temporary global Debt Security held
for its account. Each of Euroclear and CEDEL will undertake in such
circumstances to credit such interest received by it in respect of a temporary
global Debt Security to the respective accounts for which it holds such
temporary global Debt Security only upon receipt in each case of written
certification in the form and to the effect described above under "--Form,
Exchange, Registration, Conversion, Transfer and Payment" as of the relevant
Interest Payment Date regarding the portion of such temporary global Debt
Security on which interest is to be so credited.
PERMANENT GLOBAL SECURITIES
If any Debt Securities of a series are issuable in permanent global form,
the applicable Prospectus Supplement will describe the circumstances, if any,
under which beneficial owners of interests in any such permanent global Debt
Securities may exchange such interests for Debt Securities of such series and of
like tenor and principal amount in any authorized form and denomination. No
Bearer Debt Security delivered in exchange for a portion of a permanent global
Debt Security shall be mailed or otherwise delivered to any location in the
United States in connection with such exchange.
BOOK-ENTRY DEBT SECURITIES
The Debt Securities of a series may be issued in whole or in part in the
form of one or more Global Securities that will be deposited with, or on behalf
of, a depositary ("Depositary") or its nominee identified in the applicable
Prospectus Supplement. In such a case, one or more Global Securities will be
issued in a denomination or aggregate denomination equal to the portion of the
aggregate principal amount of Outstanding Debt Securities of the series to be
represented by such Global Security or Securities. The specific terms of the
depositary arrangement with respect to any portion of a series of Debt
Securities and the rights of, and limitations on, owners of beneficial interests
in any such Global Security representing all or a portion of a series of Debt
Securities will be described in the applicable Prospectus Supplement.
LIMITATIONS ON ISSUANCE OF BEARER DEBT SECURITIES
In compliance with United States federal tax laws and regulations, Bearer
Debt Securities (including securities in permanent global form that are either
Bearer Debt Securities or exchangeable for Bearer Debt Securities) will not be
offered or sold during the restricted period (as defined in United States
Treasury Regulations Section 1.163-5(c)(2)(i)(D)(7)) (generally, the first 40
days after the closing date,
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and, with respect to unsold allotments, until sold) within the United States or
to United States persons (each as defined below) other than to an office located
outside the United States of a United States financial institution (as defined
in Section 1.165-12(c)(1)(v) of the United States Treasury Regulations),
purchasing for its own account or for resale or for the account of certain
customers, that provides a certificate stating that it agrees to comply with the
requirements of Section 165(j)(3)(A), (B) or (C) of the Code and the United
States Treasury Regulations thereunder, or to certain other persons described in
Section 1.163-5(c)(2)(i)(D)(1)(iii)(B) of the United States Treasury
Regulations. Moreover, such Bearer Debt Securities will not be delivered in
connection with their sale during the restricted period within the United
States. Any underwriters and dealers participating in the offering of Bearer
Debt Securities must covenant that they will not offer or sell during the
restricted period any Bearer Debt Securities within the United States or to
United States persons (other than the persons described above) or deliver in
connection with the sale of Bearer Debt Securities during the restricted period
any Bearer Debt Securities within the United States and that they have in effect
procedures reasonably designed to ensure that their employees and agents who are
directly engaged in selling the Bearer Debt Securities are aware of the
restrictions described above. No Bearer Debt Security (other than a temporary
global Bearer Debt Security) will be delivered in connection with its original
issuance nor will interest be paid on any Bearer Debt Security until receipt by
the Company of the written certification described above under "--Form,
Exchange, Registration, Conversion, Transfer and Payment." Each Bearer Debt
Security, other than a temporary global Bearer Debt Security, will bear a legend
to the following effect: "Any United States person who holds this obligation
will be subject to limitations under the United States federal income tax laws,
including the limitations provided in Sections 165(j) and 1287(a) of the
Internal Revenue Code."
As used herein, "United States person" means any citizen or resident of the
United States, any corporation, partnership or other entity created or organized
in or under the laws of the United States and any estate or trust the income of
which is subject to United States federal income taxation regardless of its
source, and "United States" means the United States of America (including the
states and the District of Columbia) and its possessions.
EVENTS OF DEFAULT
The following will be Events of Default under the Indenture with respect to
Debt Securities of any series: (a) failure to pay principal (or premium, if any)
on any Debt Security of that series when due; (b) failure to pay any interest on
any Debt Security of that series when due, which failure continues for 30 days;
(c) failure to perform any other covenant of the Company in the applicable
Indenture or any other covenant to which the Company may be subject with respect
to Debt Securities of that series (other than a covenant solely for the benefit
of a series of Debt Securities other than that series), which failure continues
for 90 days after written notice as provided in the applicable Indenture; and
(d) certain events of bankruptcy, insolvency or reorganization.
If an Event of Default with respect to Outstanding Debt Securities of any
series shall occur and be continuing, either the Trustee or the Holders of at
least 25% in principal amount of the Outstanding Debt Securities of that series,
by notice as provided in the applicable Indenture, may declare the principal
amount (or, if the Debt Securities of that series are Original Issue Discount
Securities, such portion of the principal amount as may be specified in the
terms of that series) of all Debt Securities of that series to be due and
payable immediately, except that upon the occurrence of an Event of Default
specified in (d) above, the principal amount (or in the case of Original Issue
Discount Securities, such portion) of all Debt Securities shall be immediately
due and payable without any action by the Trustee or any Holder. At any time
after a declaration of acceleration with respect to Debt Securities of any
series has been made, but before judgment or decree based on such acceleration
has been obtained, the Holders of a majority in principal amount of the
Outstanding Debt Securities of that series may, under certain circumstances,
rescind and annul such acceleration. For information as to waiver of defaults,
see "Modification and Waiver" below.
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The Indentures will provide that, subject to the duty of the respective
Trustees thereunder during an Event of Default to act with the required standard
of care, each such Trustee will be under no obligation to exercise any of its
rights or powers under the respective Indentures at the request or direction of
any of the Holders, unless such Holders shall have offered to such Trustee
reasonable security or indemnity. Subject to certain provisions, including those
requiring security or indemnification of the applicable Trustee, the Holders of
a majority in principal amount of the Outstanding Debt Securities of any series
will have the right to direct the time, method and place of conducting any
proceeding for any remedy available to the Trustee, or exercising any trust or
power conferred on such Trustee, with respect to the Debt Securities of that
series.
No Holder of a Debt Security of any series will have any right to institute
any proceeding with respect to the applicable Indenture or for any remedy
thereunder, unless such Holder shall have previously given to the applicable
Trustee written notice of a continuing Event of Default and unless the Holders
of at least 25% in aggregate principal amount of the Outstanding Debt Securities
of the same series shall have written requests, and offered reasonable
indemnity, to such Trustee to institute such a proceeding, and the Trustee shall
not have received from the Holders of a majority in aggregate principal amount
of the Outstanding Debt Securities of the same series a direction inconsistent
with such request and shall have failed to institute such proceeding within 60
days. However, such limitations do not apply to a suit instituted by a Holder of
a Debt Security for enforcement of payment of the principal of and interest on
such Debt Security on or after the respective due dates expressed in such Debt
Security.
The Company is required to furnish to the Trustees annually a statement as
to the performance by the Company of its obligations under the respective
Indentures and as to any default in such performance.
MODIFICATION AND WAIVER
The Indenture provides that Supplemental Indentures may be entered into by
the Company and the Trustee without the consent of any Holders of Debt
Securities in certain limited circumstances, including (i) to cure any
ambiguity, omission, defect or inconsistency, (ii) to provide for the assumption
of the obligations of the Company under the Indenture upon the merger,
consolidation or sale or other disposition of all or substantially all of the
assets of the Company and its Subsidiaries taken as a whole and certain other
events specified in the "Merger, Consolidation and Sale of Substantially All
Assets" covenant, (iii) to provide for uncertificated Debt Securities in
addition to or in place of certificated Debt Securities, (iv) to comply with any
requirement of the Commission in order to effect or maintain the qualification
of the Indenture under the Trust Indenture Act of 1939, as amended, (v) to make
any change in the Debt Securities of any or all series that does not adversely
affect the rights of any Holder of Debt Securities of the affected series in any
material respect, (vi) to add Subsidiary guarantors pursuant to the procedures
set forth in the Indentures, and (vii) certain other modifications and
amendments as set forth in the Indenture.
The Indenture contains provisions permitting the Company and the Trustee,
with the written consent of the Holders of not less than a majority in aggregate
principal amount of the Debt Securities, of any series then outstanding, to
execute supplemental indentures or amendments adding any provisions to or
changing or eliminating any of the provisions of the Indenture or modifying the
rights of the Holders of the Debt Securities of such series, except that no such
supplemental indenture, amendment or waiver may, without the consent of all the
Holders of Debt Securities of such series then outstanding, among other things,
(i) reduce the principal amount of Debt Securities of such series whose Holders
must consent to an amendment or waiver, (ii) reduce the rate of or change the
time of payment of interest on any Debt Securities, (iii) change the currency in
which any amount due in respect of the Debt Securities is payable, (iv) reduce
the principal of or any premium on or change the Stated Maturity of any Debt
Securities or alter the redemption or repurchase provisions with respect
thereto, (v) reduce the relative ranking of any Debt Securities, (vi) release
any security that may have been granted in respect of the Debt Securities, (vii)
impair the right of any Holder to institute suit for enforcement of any payment
on or with respect to
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such Holder's Debt Securities and (viii) make certain other significant
amendments or modifications as specified in the Indenture.
The Holders of at least a majority in principal amount of the Outstanding
Debt Securities of any series may, on behalf of the Holders of all Debt
Securities of that series, waive compliance by the Company with certain
covenants of the applicable Indenture and any past default under the applicable
Indenture with respect to that series, except a default in the payment of the
principal of, premium, if any, or interest on, any Debt Security of that series
or in respect of a provision which under the applicable Indenture cannot be
modified or amended without the consent of the Holder of each Outstanding Debt
Security of that series affected.
CONSOLIDATION, MERGER AND SALE OF ASSETS
The Company, without the consent of any Holders of any series of outstanding
Debt Securities, may consolidate with or merge into, or transfer or lease its
assets substantially as an entirety (treating the Company and each of its
Subsidiaries as a single consolidated entity) to, any corporation, and any other
corporation may consolidate with or merge into, or transfer or lease its assets
substantially as an entirety to, the Company, provided that the corporation (if
other than the Company) formed by such consolidation or into which the Company
is merged or which acquires or leases the assets of the Company substantially as
an entirety is organized and existing under the laws of the United States of
America or any political subdivision thereof, and assumes the Company's
obligations under each series of Outstanding Debt Securities and the Indentures
applicable thereto and that the Trustee is satisfied that, after giving effect
to such transaction, no Event of Default, and no event which, after notice or
lapse of time or both, would become an Event of Default, shall have occurred and
be continuing.
DEFEASANCE
If so indicated in the applicable Prospectus Supplement with respect to the
Debt Securities of a series, the Company at its option (i) will be discharged
from any and all obligations in respect of the Debt Securities of such series
(except for certain obligations to register the transfer or exchange of Debt
Securities of such series, to replace destroyed, stolen, lost or mutilated Debt
Securities of such series, and to maintain an office or agency in respect of the
Debt Securities and hold moneys for payment in trust) or (ii) will be released
from its obligations to comply with certain covenants specified in the
applicable Prospectus Supplement with respect to the Debt Securities of such
series, and the occurrence of certain Events of Default as specified in the
applicable Prospectus Supplement with respect to the Debt Securities of such
series, shall no longer be Events of Default, if, in either case, the Company
irrevocably deposits with the applicable Trustee, in trust, money, Government
Obligations of the government issuing the currency in which the Debt Securities
of the relevant series are denominated or a combination thereof that through the
payment of interest thereon and principal thereof in accordance with the terms
will provide money in an amount sufficient to pay all the principal of and
premium, if any, and interest on the Securities of such series on the dates such
payments are due (up to the Stated Maturity Date, or the Redemption Date, as the
case may be) in accordance with the terms of such Debt Securities. Such a trust
may only be established if, among other things, (a) 123 days pass after the
deposit is made and during the 123-day period no Event of Default described in
clause (d) under "Events of Default" shall have occurred and be continuing at
the end of such period and (b) the Company shall have delivered an Opinion of
Counsel to the effect that (i) the Holders of the Debt Securities will not
recognize gain or loss for United States federal income tax purposes as a result
of such deposit or defeasance and will be subject to United States federal
income tax in the same manner as if such defeasance had not occurred, and (ii)
the trust resulting from the deposit does not constitute, or is qualified as, a
regulated investment company under the Investment Company Act of 1940. Such
opinion, in the case of defeasance under clause (i) above, must refer to and be
based upon a ruling of the Internal Revenue Service or a change in applicable
federal income tax law occurring after the date of the applicable Indenture. In
the event the Company fails to
20
<PAGE>
comply with its remaining obligations under the applicable Indenture after a
defeasance of such Indenture with respect to the Debt Securities of any series
as described under clause (ii) above and the Debt Securities of such series are
declared due and payable because of the occurrence of any undefeased Event of
Default, the amount of money and Government Obligations on deposit with the
applicable Trustee may be insufficient to pay amounts due on the Debt Securities
of such series at the time of the acceleration resulting from such Event of
Default. However, the Company will remain liable in respect to such payments.
Notwithstanding the description set forth under "Subordination of Senior
Subordinated Debt Securities and Subordinated Debt Securities" above, in the
event that the Company deposits money or Government Obligations in compliance
with the Indenture that governs any Senior Subordinated Debt Securities or
Subordinated Debt Securities, as the case may be, in order to defease all or
certain of its obligations with respect to the applicable series of Debt
Securities, the money or Government Obligations so deposited will not be subject
to the subordination provisions of the applicable Indenture and the indebtedness
evidenced by such series of Debt Securities will not be subordinated in right of
payment to the holders of applicable Senior Indebtedness to the extent of the
money or Government Obligations so deposited.
REGARDING THE TRUSTEES
The Indentures contain certain limitations on the right of each Trustee,
should it become a creditor of the Company, to obtain payment of claims in
certain cases, or to realize for its own account on certain property received in
respect of any such claim as security or otherwise. Each Trustee will be
permitted to engage in certain other transactions; however, if it acquires any
conflicting interest within the meaning of the Trust Indenture Act of 1939 and
there is a default under the Debt Securities issued under the applicable
Indenture, it must eliminate such conflict or resign.
21
<PAGE>
DESCRIPTION OF PREFERRED STOCK
The Company's Certificate of Incorporation currently authorizes the issuance
of 10,000,000 shares of Preferred Stock, par value $.01 per share, issuable in
series. The board of directors of the Company is authorized to approve the
issuance of one or more series of Preferred Stock without further authorization
of the stockholders of the Company and to fix the number of shares, the
designations, the relative rights and preferences and the limitations of any
such series.
At the date of this Prospectus, no shares of preferred stock were issued and
outstanding, and 500,000 shares of Series A Junior Participating Preferred Stock
were reserved for issuance in connection with the Company's Stockholders' Rights
Plan dated February 24, 1996 (the "Rights Plan"). See "Description of Common
Stock--Stockholders' Rights Plan." The terms of the Company's currently
authorized Series A Junior Participating Preferred Stock do not limit the
issuance of other series of Preferred Stock ranking as to dividends and payments
upon liquidation senior to, on a parity with or junior to such existing
Preferred Stock.
The applicable Prospectus Supplement will set forth the number of shares,
particular designation, relative rights and preferences and the limitations of
any series of Preferred Stock in respect of which this Prospectus is delivered.
The particular terms of any such series will include the following:
(i) The maximum number of shares to constitute the series and the
designation thereof;
(ii) The annual dividend rate, if any, on shares of the series, whether such
rate is fixed or variable or both, the date or dates from which
dividends will begin to accrue or accumulate, whether dividends will be
cumulative and whether such dividends shall be paid in cash, Common
Stock or otherwise;
(iii) Whether the shares of the series will be redeemable and, if so, the
price at and the terms and conditions on which the shares of the series
may be redeemed, including the time during which shares of the series
may be redeemed and any accumulated dividends thereon that the holders
of shares of the series shall be entitled to receive upon the
redemption thereof;
(iv) The liquidation preference, if any, applicable to shares of the series;
(v) Whether the shares of the series will be subject to operation of a
retirement or sinking fund and, if so, the extent and manner in which
any such fund shall be applied to the purchase or redemption of the
shares of the series for retirement or for other corporate purposes, and
the terms and provisions relating to the operation of such fund;
(vi) The terms and conditions, if any, on which the shares of the series
shall be convertible into, or exchangeable for, shares of any other
class or classes of capital stock of the Company or another corporation
or any series of any other class or classes, or of any other series of
the same class, including the price or prices or the rate or rates of
conversion or exchange and the method, if any, of adjusting the same;
(vii) The voting rights, if any, of the shares of the series;
(viii) The currency or units based on or relating to currencies in which such
series is denominated and/ or in which payments will or may be payable;
(ix) The methods by which amounts payable in respect of such series may be
calculated and any commodities, currencies or indices, or price, rate
or value, relevant to such calculation;
(x) Any listing of the shares of the series on a securities exchange; and
(xi) Any other preferences and relative, participating, optional or other
rights or qualifications, limitations or restrictions thereof.
22
<PAGE>
Any material United States federal income tax consequences and other special
considerations to any offered Preferred Stock will be described in the
Prospectus Supplement relating to the offering and sale of such Preferred Stock.
TRANSFER AGENT AND REGISTRAR
The transfer agent and registrar for each series of Preferred Stock will be
designated in the related Prospectus Supplement.
DESCRIPTION OF COMMON STOCK
GENERAL
The following is a description of certain general terms and provisions of
the Common Stock. The summary of terms of the Company's Common Stock contained
in this Prospectus does not purport to be complete and is subject to, and
qualified in its entirety by, the provisions of the Company's Restated
Certificate of Incorporation, Bylaws and Rights Plan, each of which has been
incorporated by reference herein.
The Company's Restated Certificate of Incorporation authorizes the issuance
of 50,000,000 shares of Common Stock, $.01 par value. All issued and outstanding
shares of Common Stock are validly issued, fully paid and nonassessable. The
holders of Common Stock are entitled to one vote for each share held on all
matters submitted to a vote of holders of Common Stock. The Common Stock does
not have cumulative voting rights. Each share of Common Stock is entitled to
participate equally in dividends, as and when declared by the Company's board of
directors, and in the distribution of assets in the event of liquidation,
subject in all cases to any prior rights of outstanding shares of the Company's
preferred stock. The shares of Common Stock have no preemptive or conversion
rights, redemption rights or sinking fund provisions.
STOCKHOLDERS' RIGHTS PLAN
On February 24, 1996, the Company's board of directors declared a dividend
distribution of one Preferred Stock Purchase Right (a "Right") for each
outstanding share of Common Stock. The description and terms of the Rights are
set forth in the Rights Agreement which is incorporated herein by reference. The
distribution was made as of March 6, 1996, to stockholders of record on that
date. Each Right entitles the registered holder of Common Stock to purchase from
the Company one one-hundredth (1/100) of a share of preferred stock, designated
as Series A Junior Participating Preferred Stock, at a price of $18.75 per one
one-hundredth (1/100) of a share, subject to adjustments. The Rights will expire
at the close of business on March 6, 2006, unless the expiration date is
extended or unless the Rights are earlier redeemed or exchanged by the Company
as described in the Rights Agreement.
Initially, the Rights will not be exercisable or represented by a separate
certificate but will trade together with the Common Stock. The Rights, unless
redeemed prior thereto, become exercisable only upon the close of business on
the day which is the earlier of (a) the tenth day after a public announcement
that a person or group of affiliated or associated persons, with certain
exceptions as noted in the Rights Agreement, has acquired beneficial ownership
of 15% or more of the Company's outstanding Common Stock (an "Acquiring Person")
or (b) the tenth business day (or such later date as may be determined by the
Company's board of directors prior to such time as any person or group of
affiliated persons becomes an Acquiring Person) after the commencement or
announcement of an intention to commence a tender or exchange offer, the
consummation of which would result in the ownership of 15% or more of the
Company's outstanding Common Stock. All issuances of Common Stock after the date
of the Rights Agreement will include Rights.
23
<PAGE>
TRANSFER AGENT AND REGISTRAR
The co-transfer agents and co-registrars for the Common Stock are Corporate
Stock Transfer, Inc., and First Interstate Bank of California.
LISTING
The Company's Common Stock is quoted on the Nasdaq National Market under the
symbol BSNX.
24
<PAGE>
DESCRIPTION OF WARRANTS
GENERAL
The Company may issue Warrants to purchase shares of Common Stock, shares of
Preferred Stock or Debt Securities. Warrants may be issued, subject to
regulatory approvals, independently or together with any Common Stock, Preferred
Stock or Debt Securities, as the case may be, and may be attached to or separate
from such Common Stock, Preferred Stock or Debt Securities. Each series of
Warrants will be issued under a separate warrant agreement (each a "Warrant
Agreement") to be entered into between the Company and a warrant agent (the
"Warrant Agent"). The Warrant Agent will act solely as an agent of the Company
in connection with the Warrants of such series and will not assume any
obligation or relationship of agency or trust for or with any holders or
beneficial owners of Warrants.
The applicable Prospectus Supplement will describe the following terms of
any Warrants in respect of which this Prospectus is delivered: (i) the title of
such Warrants; (ii) a description of the securities (which may include shares of
Common Stock, shares of Preferred Stock or Debt Securities) for which such
Warrants are exercisable; (iii) the price or prices at which such Warrants will
be issued; (iv) the periods during which the Warrants are exercisable; (v) the
number of shares of Common Stock or Preferred Stock or the amount of Debt
Securities for which each Warrant is exercisable; (vi) the exercise price for
such Warrants, including any changes to or adjustments in the exercise price;
(vii) the currency or currencies, including composite currencies, in which the
exercise price of such Warrants may be payable; (viii) if applicable, the
designation and terms of the shares of Preferred Stock with which such Warrants
are issued; (ix) if applicable, the terms of the Debt Securities with which such
Warrants are issued; (x) if applicable, the number of Warrants issued with each
share of Common Stock or Preferred Stock or Debt Security; (xi) if applicable,
the date on and after which such Warrants and the related shares of Common Stock
or Preferred Stock or Debt Securities will be separately transferable; (xii) if
applicable, a discussion of certain United States federal income tax
considerations; (xiii) any listing of the Warrants on a securities exchange; and
(xiv) any other terms of such Warrants, including terms, procedures and
limitations relating to the exchange and exercise of such Warrants.
SELLING STOCKHOLDER
Common Stock owned by Michael S. Smith, Chairman of the Board, President and
Chief Executive Officer, may be offered for Mr. Smith's account pursuant to this
Prospectus. The following table sets forth information as of September 22, 1997
regarding the Common Stock owned by Mr. Smith, which may be offered hereunder.
<TABLE>
<CAPTION>
SHARES BENEFICIALLY
SHARES BENEFICIALLY
OWNED PRIOR TO THE
OFFERING OWNED AFTER THE OFFERING
----------------------- NUMBER OF SHARES TO BE ------------------------
SELLING STOCKHOLDER NUMBER PERCENT SOLD IN THE OFFERING NUMBER PERCENT
- ------------------------------------------ ---------- ----------- -------------------------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Michael S. Smith.......................... 3,248,150(1) 30.13 Not to exceed 300,000* * *
</TABLE>
- ------------------------
* To be included in a Prospectus Supplement
(1) Includes 2,675,150 shares held by Mr. Smith; 304,300 shares held by Iris
Smith, Mr. Smith's wife; 96,000 shares held by trusts for Mr. Smith's
children, of which Mr. Smith is trustee; and 92,700 shares held by KaiTar
Foundation, a nonprofit charitable foundation of which Mrs. Smith is
president and Mr. Smith is vice-president. Mr. Smith has no voting or
investment power with respect to the shares held by Iris Smith and disclaims
beneficial ownership of such shares. Mr. Smith, in his capacity as the
trustee of the trusts for his children and as vice president of KaiTar
Foundation, has voting and investment power with respect to the shares held
in such capacity and may be deemed to be the beneficial owner of such shares
but disclaims beneficial ownership of such shares. Also includes options for
60,000 shares exercisable within 60 days and 20,000 performance shares, the
restrictions on which lapse December 31, 1999.
25
<PAGE>
PLAN OF DISTRIBUTION
The Company may offer and sell the Debt Securities, Preferred Stock, Common
Stock and Warrants to or through underwriters or dealers, and also may offer and
sell Debt Securities, Preferred Stock, Common Stock and Warrants directly to
other purchasers or through agents.
The distribution of the Securities may be affected from time to time in one
or more transactions at a fixed price or prices, which may be changed, at market
prices prevailing at the time of sale, at prices related to such market prices
or at negotiated prices.
Each Prospectus Supplement will set forth the terms of the offering of the
particular series of Securities to which the Prospectus Supplement relates,
including the name or names of any underwriters, dealers or agents, the purchase
price or prices of the Securities, the proceeds to the Company or the selling
stockholder, if applicable, from the sale of such series of Securities, the use
of such proceeds, any initial public offering price or purchase price of such
series of Securities, any underwriting discount or commission, any discounts,
concessions or commissions allowed or reallowed or paid by any underwriters to
other dealers, any commissions paid to any agents, and the securities exchanges,
if any, on which such Securities will be listed. Any initial public offering
price or purchase price and any discounts, concessions or commissions allowed or
reallowed or paid by any underwriter to other dealers may be changed from time
to time.
In connection with distributions of Common Stock or otherwise, the Company
may enter into hedging transactions with broker-dealers in connection with which
such broker-dealers may sell Common Stock registered hereunder in the course of
hedging through short sales the positions they assumed with the Company.
In connection with the sale of the Securities, underwriters or agents may
receive compensation from the Company, the selling stockholder, if applicable,
or from purchasers of Securities for whom they may act as agents in the form of
discounts, concessions or commissions. Underwriters may sell Securities to or
through dealers, and such dealers may receive compensation in the form of
discounts, concessions or commissions from the underwriters and/or commissions
from the purchasers for whom they may act as agents. Underwriters, dealers and
agents that participate in the distribution of Securities may be deemed to be
underwriters, and any discounts or commissions received by them from the Company
and any profit on the resale of Securities by them may be deemed to be
underwriting discounts and commissions under the Securities Act. Any such
underwriter or agent will be identified, and any such compensation received from
the Company will be described, in the applicable Prospectus Supplement.
The sale of all or a portion of the shares of Common Stock offered hereby by
the Selling Stockholder may be effected from time to time on any exchange on
which the Common Stock is then listed at prevailing prices at the time of such
sale, at prices related to such prevailing prices or at negotiated prices. The
Selling Stockholder may sell all or a portion of the shares offered hereby in
private transactions or in the over-the-counter market at prices related to the
prevailing prices of the shares on the Nasdaq National Market.
Under agreements which may be entered into by the Company, underwriters and
agents who participate in the distribution of Securities may be entitled to
indemnification by the Company or the selling stockholder against certain
liabilities, including liabilities under U.S. securities legislation.
The Company may grant underwriters who participate in the distribution of
Securities an option to purchase additional Securities to cover over-allotments,
if any.
Certain underwriters and selling group members (if any) who are qualifying
registered market makers on the Nasdaq National Market may engage in passive
market making transactions in the Common Stock on the Nasdaq National Market in
accordance with Rule 10b-6A under the Securities Exchange Act of 1934, as
amended, during the two business day period before commencement of offers or
sales of the Common Stock.
26
<PAGE>
The place and date of delivery for the Securities in respect of which this
Prospectus is being delivered will be set forth in the applicable Prospectus
Supplement.
If so indicated in the applicable Prospectus Supplement, the Company will
authorize underwriters or agents to solicit offers by certain institutions to
purchase Securities from the Company pursuant to delayed delivery contracts
providing for payment and delivery at a future date. Institutions with which
such contracts may be made include commercial and savings banks, insurance
companies, pension funds, investment companies, educational and charitable
institutions and others, but in all cases such institutions must be approved by
the Company. Unless otherwise set forth in the applicable Prospectus Supplement,
the obligations of any purchaser under any such contract will not be subject to
any conditions except that (i) the purchase of the Securities shall not at the
time of delivery be prohibited under the laws of the jurisdiction to which such
purchaser is subject, and (ii) if the Securities are also being sold to
underwriters acting as principals for their own account, the underwriters shall
have purchased such Securities not sold for delayed delivery. The underwriters
and such other persons will not have any responsibility in respect of the
validity or performance of such contracts.
Unless otherwise indicated in the applicable Prospectus Supplement, the
Securities in respect of which this Prospectus is being delivered (other than
Common Stock) will be a new issue of securities, will not have an established
trading market when issued and will not be listed on any securities exchange.
Any underwriters or agents to or through whom such Securities are sold by the
Company for public offering and sale may make a market in such Securities, but
such underwriters or agents will not be obligated to do so and may discontinue
any market making at any time without notice. No assurance can be given as to
the liquidity of the trading market for any such Securities.
Certain of the underwriters and their affiliates may from time to time
perform various commercial banking and investment banking services for the
Company, for which customary compensation is received.
EXPERTS
The consolidated financial statements of the Company, included in its Annual
Report on Form 10-K for the year ended December 31, 1996, incorporated by
reference in this Prospectus and elsewhere in the Registration Statement have
been audited by Arthur Andersen LLP, independent public accountants, as
indicated in their report with respect thereto, and are incorporated herein in
reliance upon the authority of said firm as experts in giving said report.
Future financial statements of the Company and the reports thereon of Arthur
Andersen LLP, or any successor independent accounting firm that has audited the
Company's financial statements, also will be incorporated by reference in this
Prospectus and elsewhere in the Registration Statement in reliance upon the
authority of such firm as experts in giving those reports to the extent said
firm has audited those financial statements and consented to the use of their
reports thereon.
Estimates of historical onshore oil and natural gas reserves of the Company
as of December 31, 1994, 1995 and 1996, incorporated by reference herein are
based upon engineering studies prepared by the Company and audited by the
independent engineering firm of Netherland, Sewell & Associates, Inc. Estimates
of historical offshore reserves of the Company as of December 31, 1996,
incorporated by reference herein are based upon engineering studies prepared by
the independent engineering firm of Ryder Scott Company Petroleum Engineers.
Such estimates are incorporated by reference herein (to the extent covered by
consents filed with the Commission) in reliance upon the authority of such firms
as experts in such matters.
LEGAL MATTERS
Certain legal matters relating to the validity of the Securities will be
passed upon for the Company by Davis, Graham & Stubbs LLP, Denver, Colorado.
Certain legal matters will be passed upon for the underwriters, if any, by the
counsel named in the applicable Prospectus Supplement.
27
<PAGE>
GLOSSARY
The terms defined in this section are used throughout this Prospectus.
2-D SEISMIC DATA. Seismic data that are acquired and processed to yield a
two-dimensional cross section of the subsurface.
3-D SEISMIC DATA. Seismic data that are acquired and processed to yield a
three-dimensional picture of the subsurface.
BCF. Billion cubic feet (of gas).
BCFE. Billion cubic feet (of gas) equivalent.
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.
GROSS ACRES. An acre in which a working interest is owned.
MMBBL. One million barrels of crude oil or other liquid hydrocarbons.
NET ACRES. The sum of the fractional working interests owned in gross acres.
PRODUCTIVE WELL. A well that is producing oil or gas or that is capable of
production.
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.
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 to share in
the production.
28
<PAGE>
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NO DEALER, SALESPERSON OR OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS, OTHER THAN THOSE CONTAINED IN OR
INCORPORATED BY REFERENCE IN THIS PROSPECTUS SUPPLEMENT OR THE PROSPECTUS, IN
CONNECTION WITH THE OFFER MADE BY THIS PROSPECTUS SUPPLEMENT AND PROSPECTUS AND,
IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATIONS MUST NOT BE RELIED UPON AS
HAVING BEEN AUTHORIZED BY THE COMPANY OR ANY UNDERWRITER OR DEALER. NEITHER THE
DELIVERY OF THIS PROSPECTUS SUPPLEMENT OR THE PROSPECTUS NOR ANY SALE MADE
HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE AN IMPLICATION THAT THERE HAS
BEEN NO CHANGE IN THE FACTS SET FORTH IN THIS PROSPECTUS SUPPLEMENT AND
PROSPECTUS, OR IN THE AFFAIRS OF THE COMPANY SINCE THE DATES HEREOF. THIS
PROSPECTUS SUPPLEMENT AND THE PROSPECTUS DO NOT CONSTITUTE AN OFFER OR
SOLICITATION BY ANYONE IN ANY JURISDICTION IN WHICH SUCH OFFER OR SOLICITATION
IS NOT AUTHORIZED OR IN WHICH THE PERSON MAKING SUCH OFFER OR SOLICITATION IS
NOT QUALIFIED TO DO SO OR TO ANYONE TO WHOM IT IS UNLAWFUL TO MAKE SUCH OFFER OR
SOLICITATION.
--------------------------
TABLE OF CONTENTS
PROSPECTUS SUPPLEMENT
<TABLE>
<CAPTION>
PAGE
---------
<S> <C>
Prospectus Supplement Summary.................. S-3
Uncertainty of Forward-Looking Information..... S-10
Risk Factors................................... S-11
Use of Proceeds................................ S-16
Capitalization................................. S-17
Price Range of Common Stock and Dividend
Policy....................................... S-18
Selected Historical Financial Information...... S-19
Management's Discussion and Analysis of
Financial Condition and Results of
Operations................................... S-21
Business and Properties........................ S-30
Management..................................... S-41
Selling Stockholder............................ S-44
Underwriting................................... S-45
Experts........................................ S-46
Legal Matters.................................. S-46
Glossary....................................... S-47
Index to Financial Statements.................. S-49
PROSPECTUS
Available Information.......................... 2
Incorporation of Certain Documents by
Reference.................................... 2
Special Note Regarding Forward-Looking
Statements................................... 3
Risk Factors................................... 4
The Company.................................... 9
Use of Proceeds................................ 11
Ratio of Earnings to Fixed Charges............. 11
Description of Debt Securities................. 11
Description of Preferred Stock................. 22
Description of Common Stock.................... 23
Description of Warrants........................ 25
Selling Stockholder............................ 25
Plan of Distribution........................... 26
Experts........................................ 27
Legal Matters.................................. 27
Glossary....................................... 28
</TABLE>
2,700,000 SHARES
[LOGO]
BASIN EXPLORATION, INC.
COMMON STOCK
--------------------
P R O S P E C T U S
--------------------
MORGAN KEEGAN & COMPANY, INC.
HOWARD, WEIL,
LABOUISSE, FRIEDRICHS
INCORPORATED
PETRIE PARKMAN & CO.
RAUSCHER PIERCE REFSNES, INC.
OCTOBER , 1997
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