<PAGE>
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________ to ___________
Commission File Number 0-20125
BASIN EXPLORATION, INC.
(Exact name of registrant as specified in its charter)
DELAWARE 84-1143307
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
370 17TH STREET, SUITE 3400, DENVER, CO 80202
(Address of principal executive offices) (Zip Code)
(303) 685-8000
(Registrant's telephone number, including area code)
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
YES X NO
----- -----
Indicate the number of shares outstanding of each of the issuer's classes of
Common stock, as of the latest practicable date.
<TABLE>
<CAPTION>
Outstanding at
Class April 30, 1999
---------------------------- -----------------
<S> <C>
Common stock, $.01 par value 14,045,000 shares
</TABLE>
<PAGE>
BASIN EXPLORATION, INC.
INDEX
<TABLE>
<CAPTION>
PART I. FINANCIAL INFORMATION Page
----
<S> <C>
Item 1. Consolidated Financial Statements
Consolidated Balance Sheets as of
December 31, 1998 and March 31, 1999.................................. 3
Consolidated Statements of Operations for the
three months ended March 31, 1998 and 1999............................ 5
Consolidated Statements of Changes in
Stockholders' Equity.................................................. 6
Consolidated Statements of Cash Flows for the
three months ended March 31, 1998 and 1999............................ 7
Notes to Consolidated Financial Statements............................ 8
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations................................... 9
Item 3. Quantitative and Qualitative Disclosures about Market Risk............ 22
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K...................................... 23
SIGNATURES.......................................................................... 25
</TABLE>
2
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PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1998 AND MARCH 31, 1999
<TABLE>
<CAPTION>
ASSETS
(In thousands)
December 31, March 31,
1998 1999
------------ ---------
<S> <C> <C>
CURRENT ASSETS
Cash and equivalents $ 331 $ 20
Accounts receivable 10,036 9,227
Prepaids and other 2,752 3,791
--------- ---------
13,119 13,038
--------- ---------
PROPERTY AND EQUIPMENT, at cost:
Oil and gas properties, under the full
cost method of accounting
Proved 265,826 287,299
Unproved 34,039 33,902
Less accumulated depreciation,
depletion and amortization (113,462) (121,819)
--------- ---------
186,403 199,382
Furniture and equipment, net 1,408 1,306
--------- ---------
187,811 200,688
--------- ---------
OTHER ASSETS 233 1,117
--------- ---------
$ 201,163 $ 214,843
--------- ---------
--------- ---------
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
3
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BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1998 AND MARCH 31, 1999
<TABLE>
<CAPTION>
LIABILITIES AND STOCKHOLDERS' EQUITY
(In thousands, except share data) December 31, March 31,
1998 1999
------------ ---------
<S> <C> <C>
CURRENT LIABILITIES:
Accounts payable $ 12,465 $ 14,409
Accrued liabilities 13,620 14,930
Current portion of long-term debt 258 156
--------- ---------
26,343 29,495
--------- ---------
LONG-TERM DEBT, net of current portion 80,000 91,000
OTHER LONG-TERM OBLIGATIONS 601 45
STOCKHOLDERS' EQUITY:
Preferred stock, par value $.01 per
share; 10,000,000 shares authorized,
shares issued and outstanding - -
no shares issued and outstanding
Common stock, par value $.01 per
share, 50,000,000 shares authorized,
14,151,000 and 14,213,000 shares
issued, respectively 142 142
Additional paid-in capital 113,136 113,618
Accumulated deficit (16,488) (16,886)
Common stock held in treasury, at cost,
186,000 shares (2,571) (2,571)
--------- ---------
94,219 94,303
--------- ---------
$ 201,163 $ 214,843
--------- ---------
--------- ---------
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
4
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
For the Three Months Ended
March 31,
(In thousands, except per share data) 1998 1999
------------ ------------
<S> <C> <C>
REVENUE:
Oil sales $ 2,690 $ 2,246
Gas sales 7,545 10,796
Interest and other 21 13
---------- ----------
10,256 13,055
---------- ----------
COSTS AND EXPENSES:
Lease operating expenses 2,143 2,455
Production taxes 234 76
Depreciation, depletion and amortization 5,986 8,546
General and administrative, net 1,112 1,427
Interest expense 413 949
---------- ----------
9,888 13,453
---------- ----------
INCOME (LOSS) BEFORE INCOME TAXES 368 (398)
Income tax provision 129 -
---------- ----------
NET INCOME (LOSS) $ 239 $ (398)
---------- ----------
---------- ----------
EARNINGS (LOSS) PER SHARE:
Basic $ 0.02 $ (0.03)
---------- ----------
---------- ----------
Diluted $ 0.02 $ (0.03)
---------- ----------
---------- ----------
WEIGHTED AVERAGE COMMON
SHARES OUTSTANDING:
Basic 13,784 13,973
Diluted 14,237 13,973
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements
5
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
FOR THE PERIOD FROM JANUARY 1, 1998 THROUGH MARCH 31, 1999
<TABLE>
<CAPTION>
RETAINED
ADDITIONAL EARNINGS TOTAL
COMMON STOCK PAID-IN TREASURY STOCK (ACCUMULATED STOCKHOLDERS
(In thousands) SHARES AMOUNT CAPITAL SHARES AMOUNT DEFICIT) EQUITY
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCES, January 1, 1998 13,833 $ 138 $ 110,627 (120) $(1,412) $ 12,012 $121,365
Issuance of common stock 130 2 627 - - - 629
Exercise of warrants for 79 1 1,107 (62) (1,108) - -
common stock
Purchase of treasury stock - - - (4) (51) - (51)
Issuance and vesting of
restricted stock 109 1 775 - - - 776
Net income (loss) - - - - - (28,500) (28,500)
------------------------------------------------------------------------------------------------
BALANCES, December 31, 1998 14,151 142 113,136 (186) (2,571) (16,488) 94,219
Issuance of common stock 12 - 62 - - - 62
Issuance and vesting of
restricted stock 50 - 420 - - - 420
Net income (loss) - - - - - (398) (398)
------------------------------------------------------------------------------------------------
BALANCES, March 31, 1999 14,213 $ 142 $ 113,618 (186) $(2,571) $ (16,886) $94,303
------------------------------------------------------------------------------------------------
------------------------------------------------------------------------------------------------
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
6
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
For the Three Months Ended
March 31,
(In thousands) 1998 1999
------------ ------------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ 239 $ (398)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities -
Depreciation, depletion and amortization 5,986 8,546
Deferred income tax expense 129 -
Stock compensation expense 202 254
Other - 16
------------ ------------
6,556 8,418
Changes in operating assets and liabilities -
Decrease (increase) in
Receivables (6,104) 809
Prepaids and other 174 (939)
(Decrease) increase in -
Accounts payable and accrued expenses 657 2,982
Ad valorem taxes and other (273) 4
------------ ------------
Net cash provided by operating activities 1,010 11,274
------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital additions (23,281) (23,977)
Deposits on offshore leases (3,989) (566)
Proceeds from sale of property and equipment 20 2,438
------------ ------------
Net cash used in investing activities (27,250) (22,105)
------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from notes payable and long-term debt 31,500 23,500
Principle payments on notes payable and long-term debt (5,538) (12,602)
Proceeds from sale of stock - 62
Debt issuance costs and other (5) (440)
------------ ------------
Net cash provided by (used in) financing activities 25,957 10,520
------------ ------------
DECREASE IN CASH AND EQUIVALENTS (283) (311)
CASH AND EQUIVALENTS, beginning of period 531 331
------------ ------------
CASH AND EQUIVALENTS, end of period $ 248 $ 20
------------ ------------
------------ ------------
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest $ 283 $ 1,369
------------ ------------
------------ ------------
Cash paid for income taxes $ - $ -
------------ ------------
------------ ------------
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
7
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) UNAUDITED 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 March 31, 1999, and the results of operations and cash
flows for the three-month 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 Annual Report on Form 10-K for the year ended
December 31, 1998.
(2) ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities. The Statement establishes accounting and reporting
standards requiring that every derivative instrument including certain
derivative instruments embedded in other contracts be recorded on the balance
sheet as either an asset or liability measured at its fair value and that
changes in the derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. The Company is required to
adopt the Statement as of January 1, 2000, but may implement the Statement as
of the beginning of any fiscal quarter prior to that date. Statement 133
cannot be applied retroactively. The Company has not yet quantified the
impacts of adopting Statement 133 or determined the timing or method of
adoption. However, Statement 133 could increase the volatility of the
Company's earnings and other comprehensive income.
(3) ACCOUNTING FOR 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 acquisition,
exploration and development of oil and gas properties are capitalized. 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. Calculation of the full cost ceiling includes an estimate of the
discounted value of future net revenue attributable to proved reserves using
various assumptions and parameters consistent with promulgations of the
Securities and Exchange Commission, and such calculation is sensitive to
changes in prevailing oil and gas sales prices. Oil and natural gas prices
are volatile and reflect seasonal factors, as well as other supply and demand
conditions. A decline in prices subsequent to April 1, 1999 could result in a
requirement that the Company recognize an impairment expense in a future
period.
8
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following discussion is intended to assist in an understanding of the
Company's results of operations and its present financial condition. The
Company's consolidated financial statements and notes thereto contain
additional detailed information that should be referred to in conjunction
with a review of this material.
Certain statements in this discussion may be forward looking. Such forward
looking statements involve risks and uncertainties, including those discussed
below, that could cause actual results to differ significantly from those
expressed. See "Forward Looking Statements."
HISTORY AND OVERVIEW
Basin is a domestic independent oil and gas company that conducts
exploration, acquisition, exploitation and production activities in the
shallow waters of the Gulf of Mexico and selected areas onshore.
The Company commenced operations in 1981 and completed an initial public
offering of its common stock in 1992. From its inception through 1991, Basin
primarily acquired, developed and exploited properties in the
Denver-Julesburg ("D-J") Basin in eastern Colorado. The Company subsequently
expanded into other areas within the Rocky Mountain region and initiated
exploration activities.
During 1995, the Company's capital expenditures on oil and gas properties
declined to $16 million, from $67 million the year before, due primarily to
fewer quality investment opportunities identified in the Company's core
operating areas and limited borrowing capacity under the Company's revolving
line of credit with its bank group (the "Credit Facility"). Each of these
factors was exacerbated by depressed regional gas prices.
In response to these developments and management's assessment of alternative
investment opportunities, the Company implemented a significant redirection
of its business strategy and operations between late-1995 and mid-1996, which
included: (i) the addition of new financial, technical and business
development members to its senior management; (ii) the sale of its D-J Basin
properties for $123.5 million (the "D-J Sales"); (iii) establishment of a
Houston-based Gulf of Mexico exploration team through hiring geoscientists
and petroleum engineers with substantial experience operating in the shallow
waters of the Gulf of Mexico; and (iv) a substantial reduction in corporate
general and administrative overhead.
The D-J Sales, which occurred in two transactions closed in March and June
1996, enabled the Company to eliminate its long-term debt and establish cash
reserves, thus providing considerable liquidity for investments in new
capital projects. However, the divestitures reduced the Company's estimated
proved oil and gas reserves and production rates at the time by approximately
70%, resulting in a significant initial decline in revenue and cash flow.
The Company began Gulf of Mexico activities in 1996 with no initial property
base in the region and early investments related primarily to acquisitions of
three-dimensional seismic data and exploratory leasehold interests and
overhead. The Company's first significant discovery in the Gulf of Mexico was
the Eugene Island Block 65 #1 well, which was drilling at the end of 1996 and
completed in 1997. The Company realized first production from Gulf of Mexico
assets in August 1997 when it brought two wells
9
<PAGE>
drilled on Eugene Island Block 65 on-line, providing the first significant
addition to the Company's producing property base following the D-J Sales.
The Company added other proved properties in the Gulf of Mexico in 1997 and
1998 through both exploratory drilling and acquisitions and as of December
31, 1998 owned interests in 18 proved properties in the area, of which 14
were producing and four were under development for first production. First
production was established on two of these properties early in the second
quarter of 1999. The Company's estimated proved oil and gas reserves
increased from 62.6 Bcfe as of December 31, 1995, pro forma the D-J Sales, to
179.5 Bcfe at the end of 1998. As further described below, Basin's net
production has increased significantly since mid-1997, as Gulf of Mexico
properties have been brought on-line.
During 1996, 1997, 1998, and the first three months of 1999, the Company's
capital expenditures on oil and gas activities totaled approximately $22.8
million, $105.6 million, $106.7 million and $22.5 million, respectively.
Over 90% of these investments related to operations in the Gulf of Mexico,
including costs incurred for exploratory leaseholds, geological and
geophysical data, exploratory drilling, completion and development
activities, and acquisitions of proved properties. These activities
included drilling a total of 36 wells in the Gulf of Mexico through March 31,
1999, of which 22, or 61%, have been successful. Two of five wells that the
Company participated in drilling in the first quarter of 1999 were successful.
The Company closed the first quarter of 1999 with a working capital deficit
of approximately $16.5 million, long-term debt of $91.0 million, and
stockholders' equity of $94.3 million. Stockholders' equity at the end of
the period reflected the impact of a $38.5 million pre-tax non-cash
impairment charge in the fourth quarter of 1998 to reduce the carrying value
of the Company's oil and gas properties. This charge, which had no impact on
the Company's cash flow or its borrowing capacity under the Credit Facility,
was precipitated by low oil and gas prices in effect at the end of 1998.
The Company's preliminary budget for 1999 provides for capital investments of
approximately $65 million, subject to increase for proceeds from asset sales.
This budget provides for exploratory drilling activities comparable to the
level of such activities in 1998, and for continued expeditious development
of drilling successes. Compared to 1998, the 1999 budget provides for a
smaller investment in prospect leaseholds, and anticipates cost savings
realizable from lower rates for drilling rigs and other oilfield goods and
services. This budget may be revised up or down due to a number of factors,
including future developments that impact availability of capital.
OPERATING ENVIRONMENT
Basin's results of operations are significantly impacted by oil and gas price
levels, which are volatile and largely beyond the Company's control. Changes
in oil and gas prices can also impact the amount and terms of external
capital resources available to the Company.
Gas prices generally respond to North American supply and demand conditions,
including the effects of weather, whereas oil prices reflect global supply
and demand conditions to a greater degree, including the impact on supply of
decisions by petroleum exporting countries. Despite temporary periods of
interrupted growth, oil and gas demand has generally increased over time.
Short-term fluctuations in demand can significantly impact prices, however.
During most of 1998 and the first quarter of 1999, the markets for both oil
and gas generally reflected ample supply and price weakness due to a number
of factors, including a second consecutive unusually warm winter in North
America. Since mid-March 1999, oil and gas prices have increased, apparently
in response to announced production cut-backs by
10
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petroleum exporting countries and expectations of reduced productive capacity
caused by declines in drilling activity. There are well-developed futures
markets for oil and gas that provide indications of expected future prices
for each product. These prices are often substantially different than current
prices reflected on spot markets. Presently, these futures markets reflect
expectations of oil and gas prices sustained at levels above the levels that
prevailed during most of 1998 and early 1999, particularly for gas, which
accounted for 85% of the Company's total production in the first quarter of
1999. Expectations will change in response to future developments and
indicated future prices may not actually materialize.
Hedging transactions can be entered into based on prices reflected in
commodity futures markets. The Company periodically enters into fixed price
sales agreements or other hedging transactions to take advantage of prices
that it believes to be attractive and to reduce risks related to potential
price declines, including the risk of being unable to make capital
investments at targeted levels. The Company has executed various hedging
transactions to mitigate its exposure to declines in oil and gas prices, as
described herein under Liquidity and Capital Resources. However, since its
hedges cover only a portion of its anticipated future production, the Company
remains vulnerable to the potential effects of a decline in prices. Such
hedges also can reduce the benefits realized by the Company from increases in
oil and gas prices.
For much of the past year, the decline in oil and gas prices negatively
impacted availability of capital resources for most energy companies,
including Basin. Besides unfavorably affecting cash flow, this weakness in
oil and gas prices increased the cost of, and reduced opportunities for,
issuance of long-term debt or equity securities. Increases in oil and gas
prices, as noted above, have resulted in some recent improvement in these
conditions.
For oil and gas producers, the impairment of capital resources during much of
the past year has been partially mitigated by certain improvements in the
operating environment. In the opinion of management, diminished capital
resources for energy companies, in the aggregate, has resulted in
significant overall improvement in the quality and terms of investment
opportunities available, compared to the period preceding the decline in oil
and gas prices that occurred in 1998 and early 1999. In addition to a more
favorable market for acquirers of exploratory prospects or producing
properties, there have been substantial reductions in the costs of oilfield
goods and services. At various times in the recent past, demand for oil and
gas drilling rigs and other oilfield products and services has strained
available capacity, leading to high cost levels, delays in obtaining
materials and services, and decreased dependability in the quality of goods
and services. Such conditions do not generally apply presently, and
availability of and costs for such goods and services have improved markedly
since mid-1998. As an example, the day rate for a typical shallow-water
jack-up drilling rig used by the Company in the Gulf of Mexico has declined
from approximately $40,000 to $15,000. Other costs have declined by smaller
amounts, but still significantly. As noted, these conditions reflect reduced
demand for such goods and services in an environment of relatively low oil
and gas prices and, therefore, some reversal would be expected with stronger
oil and gas prices.
The Company's Gulf of Mexico exploration activities are dependent on the
Company's ability to continue to identify prospects and obtain interests in
prospect leaseholds. The Company generally utilizes speculative
three-dimensional seismic data as a tool in its prospect generation. This
data is not proprietary and is available to competitors, which tends to
increase competition for, and cost of, available prospects. From the
beginning of 1998 through the end of the first quarter of 1999, the Company
was successful in expanding its inventory of potential exploratory drilling
locations from approximately 30 to 40, while drilling 20 test wells. The
Company also submitted high bids for five leases with identified
11
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exploratory prospects at a Central Gulf of Mexico lease sale held in March
1999, of which one lease has been awarded by the Minerals Management Service
and four remain under review. This inventory of prospects, the majority of
which are 100%-owned by the Company, represents more than a two-year set of
drilling opportunities for Basin, based on the Company's historical and
anticipated drilling activity levels. However, the Company faces competition
for prospects from many better-capitalized oil and gas companies and there is
no assurance that over the longer term, the Company will be able to continue
to acquire interests in prospects at acceptable costs to replenish its
inventory of prospects as these are drilled. The Company seeks to mitigate
this risk by pursuing prospect ownership through a number of avenues,
including lease sales, farm-ins, exchanges, and acquisitions. The Company
also plans to selectively evaluate and pursue other investment opportunities,
including onshore exploration and acquisitions of properties with proved oil
and gas reserves, to complement its core exploration activities in the Gulf
of Mexico.
RESULTS OF OPERATIONS
The following operating and financial data is provided to assist in
understanding results of operations for the periods presented.
<TABLE>
<CAPTION>
Quarter Ended March 31, March 31,
- -----------------------------------------------------------------------
1998 1999
- -----------------------------------------------------------------------
<S> <C> <C>
PRODUCTION:
Oil (MBbl) 183 165
Gas (MMcf) 3,400 5,803
Total gas equivalents (MMcfe) 4,498 6,793
REVENUE (IN THOUSANDS):
Oil sales $ 2,690 $ 2,246
Gas sales $ 7,545 $10,796
Total oil and gas sales $10,235 $13,042
AVERAGE SALES PRICE:
Oil (per Bbl) $ 14.69 $ 13.58
Gas (per Mcf) $ 2.22 $ 1.86
Total gas equivalents (per Mcfe) $ 2.27 $ 1.92
EXPENSES (per Mcfe):
Lease operating expenses $ 0.48 $ 0.36
Production taxes $ 0.05 $ 0.01
Depreciation, depletion and amortization $ 1.33 $ 1.26
General and administrative, net $ 0.25 $ 0.21
</TABLE>
REVENUE. Oil and gas sales revenue for the three months ended March 31, 1999
totaled $13.0 million, representing an increase of $2.8 million, or 27%,
compared to the first quarter of 1998. A 51% increase in net oil and gas
production was partially offset by a 15% decline in unit prices, based on net
equivalent unit measures. The increase in oil and gas production is
attributable to contributions in the current period from thirteen GOM
properties, compared to seven in the prior-year period. Due to the
additional GOM production, which is predominantly natural gas, and lower oil
production from onshore properties on which investments were deferred due to
low oil prices, gas increased from 76% of net equivalent units produced in
the first quarter of 1998 to 85% of total oil and gas production in the first
quarter of 1999. See "Liquidity and Capital Resources" for additional
discussion of the Company's oil and gas production. Hedging transactions had
the effect of increasing oil and gas sales by $0.3 million, or $0.08 per
Mcfe, and by $1.4 million, or $0.20 per Mcfe, in the three-month periods
ended March 31, 1998 and 1999, respectively.
LEASE OPERATING EXPENSES. Due to an increased number of producing properties
and higher production levels, lease operating expenses for the three months
ended March 31, 1999 increased by $0.3 million,
12
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or 15%, from the amount reported for the comparable period in the prior year.
However, lease operating expenses per Mcfe produced declined by 25%, from
$0.48 in the quarter ended March 31, 1998 to $0.36 during the three months
ended March 31, 1999, due to increased production in the current period from
GOM wells, which typically have significantly lower average unit operating
costs than the Company's Rocky Mountain properties.
PRODUCTION TAXES. Production taxes for the three months ended March 31, 1999
were $0.1 million, representing a decrease of $0.2 million, or 68%, compared
to 1998, due to reduced revenues from onshore properties caused by lower oil
and gas prices and a decline in production from such properties. Production
taxes as a percentage of oil and gas sales for the three months ended March
31, 1999 were 0.6%, compared to 2.3% in 1998, due to a greater portion of
sales in 1999 attributable to properties in federal waters offshore, which
are generally not subject to production taxes.
DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and
amortization expense for the three months ended March 31, 1999 was $8.5
million, representing an increase of $2.6 million, or 43%, compared to 1998.
The increase was attributable to the 51% increase in production volumes in
1999 as compared to 1998, offset by a decrease in the per-unit depletion
rate. The depletion rate of $1.23 per Mcfe produced in the three months
ended March 31, 1999 represented a 4% decrease from the $1.28 per Mcfe
average depletion rate during 1998. The lower rate is principally due to the
effects of a property impairment charge recorded by the Company in the fourth
quarter of 1998.
GENERAL AND ADMINISTRATIVE, NET. General and administrative expenses for the
three months ended March 31, 1999 were $1.4 million, representing an increase
of $0.3 million, or 28%, as compared to 1998. The increase resulted from
incremental costs incurred to manage expanded operations in the GOM and
greater stock-based incentive compensation accruals. Stock compensation
expense relates to annual grants to employees of restricted stock, including
shares awarded to management that will be earned only if certain performance
measures are achieved by the Company. Expense is recognized based on vesting
schedules and changes in the price of the Company's stock during applicable
vesting periods.
INTEREST EXPENSE. Interest expense for the three months ended March 31, 1999
totaled $0.9 million, representing an increase of $0.5 million, or 130%,
compared to the first quarter of 1998. The variance was attributable to an
increase in average borrowings offset by a slight decrease in average
effective interest rates. Interest expense in 1999 excludes $0.6 million of
interest capitalized to unproved property costs in accordance with Statement
of Financial Accounting Standards No. 34. During the quarter ended March 31,
1999, the Company had average outstanding debt of $88.5 million, with an
average effective interest rate of 6.8%, compared to average debt of $22.6
million and an average interest rate of 6.9% in the comparable 1998 period.
INCOME TAX BENEFIT (PROVISION). The income tax provision for 1998
approximates the amount that would be calculated by applying statutory income
tax rates to income before income taxes. No net income tax benefit has been
recognized in 1999 due to an equivalent increase in the deferred tax asset
valuation allowance.
13
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LIQUIDITY AND CAPITAL RESOURCES
Historically, the Company's principal sources of capital have been cash flow
from operations, the Credit Facility, proceeds from asset sales, and proceeds
from sales of common stock. The Company's principal uses of capital have been
for the exploration, acquisition, development and exploitation of oil and gas
properties.
For 1999, the Company has established an initial budget for exploration and
development activities of approximately $65 million, subject to potential
increase for proceeds from asset sales. The Company anticipates being able to
fund such investments with cash flow from operations and additional
borrowings under the Credit Facility. This budget is subject to revision to
reflect future developments. It may be impacted by oil and gas price levels,
future re-determinations of the borrowing base under the Credit Facility, and
other factors. The budget is not predicated on a future sale of securities,
but the Company may choose to issue securities in certain circumstances, in
which case the level of the Company's capital expenditures would likely
increase. Compared to actual capital expenditures in 1998 of $106.7 million,
the lower budget presently established for 1999 reflects a number of
considerations including, but not limited to, lower assumed oil and gas
prices and higher initial debt levels. The impact on drilling activity in
the current year, compared to 1998, is expected to be modest, as most of the
decline in expenditures is expected to be offset by lower service sector
costs or reflected in reduced investments in prospect leaseholds. The
Company's investments in leaseholds in 1998 significantly increased its
inventory of exploratory prospects in the Gulf of Mexico. The Company's
initial budget for 1999 anticipates investments at a level aiming to
approximately maintain, rather than expand, its inventory of Gulf of Mexico
prospects.
The Company's accrual-basis capital expenditures during the first quarter of
1999, plus deposits for five leases for which the Company submitted apparent
winning bids at the Central GOM leasesale held March 17, 1999, totaled
approximately $23.1 million. Net cash provided by operations before changes
in working capital totaled $8.4 million during the recent three-month period.
Other sources of funds for investments during the quarter included $11.0
million of net borrowings under the Credit Facility, a $3.2 million reduction
in net working capital, and $2.4 million of proceeds from asset sales. The
Company closed the first quarter of 1999 with a working capital deficit of
approximately $16.5 million and long-term debt of $91.0 million, all of which
was outstanding under the Credit Facility. The borrowing base established
under the Credit Facility is currently $110 million.
PRODUCTION AND CASH FLOW
The Company's cash flow from operations is generally determined largely by
its production level and oil and gas prices. Since 1996, the Company has made
significant investments to initiate and then expand its operations in the
Gulf of Mexico. These investments have resulted in a production ramp-up that
increased the Company's production from an average rate of 11.2 MMcfe per day
in the second quarter of 1997, prior to commencement of Gulf of Mexico
production, to an average of 75.5 MMcfe per day in the first quarter of 1999.
Production added late in the first quarter and early in the second quarter
of 1999 increased the Company's net production rate to a recent level above
100 MMcfe per day.
Based primarily on estimates reflected in the Company's year-end 1998 reserve
reports and production levels achieved to-date, the Company anticipates that
its net production in 1999 will be at least 50%
14
<PAGE>
greater than during 1998, when production totaled 21,966 MMcfe, or an average
of 60.2 MMcfe per day. The expected increase is attributable primarily to
projected production from Gulf of Mexico properties with proved reserves at
the end of 1998 that were either on-line for only a portion of 1998 or had
not yet commenced producing. Partially offsetting these additions will be
natural depletion-related declines in production from existing producing
wells. Actual realization of the production increases projected for 1999 will
be dependent upon meeting scheduled dates for commencement of production from
wells not yet on-line at the end of 1998, and upon achieving projected
performance from major wells, including certain wells with little or no
production history. Although management and the Company's independent
petroleum engineering consultants believe the projections are reasonable,
there is no assurance that they will be met. See "Forward Looking
Statements" for a description of certain risks that may impact the Company's
ability to achieve projected production levels.
MARKETING AND HEDGING TRANSACTIONS
The Company's production is generally sold under month-to-month contracts at
prevailing prices. From time-to-time, however, as conditions are deemed to
warrant, Basin has entered into hedging transactions or fixed price sales
contracts for a portion of its oil and gas production. The purposes of these
transactions are to limit the Company's exposure to future oil and gas price
declines and achieve a more predictable cash flow. However, such contracts
also limit the benefits the Company would realize if prices increase.
Hedging contracts increased the Company's revenue by $0.3 million and $1.4
million in the three-month periods ended March 31, 1998 and 1999,
respectively.
Through May 7, 1999, the Company had entered into the following fixed price
swap and collar arrangements covering the period beginning April 1, 1999 (one
MMBtu approximates one Mcf of natural gas):
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------------------
GAS SWAPS OIL SWAPS OIL COLLARS
- -------------------------------------------------------------------------------------------------------------------------------
Average Daily NYMEX Average Daily NYMEX Average Daily NYMEX NYMEX
Time Period Volume (MMBtu) Price/MMBtu Volume (Bbl) Price/Bbl Volume (Bbl) Floor Price/Bbl Ceiling Price/Bbl
- -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
4/1/99-6/30/99 53,300 2.09 1,500 16.67 1,000 14.00 16.00
- -------------------------------------------------------------------------------------------------------------------------------
7/1/99-9/30/99 50,000 2.10 1,000 14.00 16.00
- -------------------------------------------------------------------------------------------------------------------------------
10/1/99-12/31/99 38,300 2.09 1,000 14.00 16.00
- -------------------------------------------------------------------------------------------------------------------------------
1/1/00-12/31/00 3,300 2.15
- -------------------------------------------------------------------------------------------------------------------------------
1/1/01-12/31/03 10,000 2.15
- -------------------------------------------------------------------------------------------------------------------------------
</TABLE>
In addition, the Company has periodically entered into spread trades or
options transactions related to oil or natural gas futures markets. Under a
spread trade, fixed prices under a hedging contract are determined in the
future by reference to the price of an underlying contract. Such positions
may enable the Company to lock in favorable fixed prices for future hedging
positions, but can also result in unfavorable fixed price contracts if the
related reference price declines. As of May 7, 1999, the Company had an
outstanding natural gas spread trade that provides for a fixed price for
10,000 MMBtu per day for the period of March 2000 through October 2000 to be
established in the future, when so elected by the Company, at a price equal
to the NYMEX February 2000 contract price less $0.41. As of May 7, 1999, the
Company had also sold the following call options: 20,000 MMBtu of natural gas
per day for the period from April 1999 through November 1999, at a strike
price of $1.95 per MMbtu; 10,000 MMBtu of natural gas per day for the period
from April 1999 through December 2001, at a strike price of $2.50 per MMBtu;
500 barrels of oil per day for the period from April 1999 through June 1999,
at a strike price of $16.00 per barrel; and 1,000 barrels of oil per day for
the period from July 1999 through December 1999, at a strike price of $16.75
per barrel.
15
<PAGE>
CREDIT FACILITY
Effective January 1, 1999, the Company entered into an Amended and Restated
Credit Agreement (the "Credit Agreement") with its existing bank group that
provides for borrowings of up to $110 million under two combined facilities.
Facility A, currently established at $90 million, represents the borrowing
base that is considered to be "conforming" based upon the banks' customary
practices and standards in making conventional borrowing base determinations
for oil and gas producers. Facility B, which is currently established at $20
million, is a shorter-term supplemental line of credit. Interest rates
applied to borrowings under the Credit Agreement are determined by reference
to the prime rate or LIBOR, at the Company's election. Facility A provides
for a varying spread of 0% to 0.25% to be added to the prime rate, or 0.75%
to 1.5% to be applied to LIBOR, based upon the Company's facility usage
ratio. Facility B provides for a spread of 3.5% to be added to the prime
rate, or 4.75% to be applied to LIBOR, subject to a 0.25% increase in such
spreads effective June 1, 1999.
The Credit Agreement provides for borrowings to be revolving loans until
November 30, 2001, at which time the outstanding balance will be converted
into a four-year amortizing term loan unless the Credit Agreement is amended,
and subject to the scheduled termination of Facility B effective May 31,
2000. The borrowing base under the Credit Agreement is scheduled to be
re-determined at three-month intervals until Facility B is retired, and then
at six-month intervals until the revolving loan is converted into a term
loan. The next re-determination is scheduled to occur as of June 1, 1999.
The Credit Agreement contains various covenants, including ones that could
limit the Company's ability to incur other debt, dispose of assets, pay
dividends, or repurchase stock. Pursuant to the Credit Agreement,
substantially all of the Company's producing properties are subject to
mortgages in favor of the banks and the Company's remaining properties are
subject to a negative pledge.
The weighted average interest rate on borrowings outstanding under the Credit
Agreement at March 31, 1999 was 6.5%. The Company's annual interest costs
will fluctuate based upon fluctuations in short-term interest rates. Assuming
debt outstanding during 1999 remained unchanged from the amount outstanding
at March 31, 1999, the annual impact on interest expense of a ten percent
change in the average interest rate would be approximately $0.5 million,
before amounts capitalized. As the interest rate is variable and is
reflective of current market conditions, the carrying value of the Company's
debt approximates its fair value.
Borrowing base re-determinations conducted by the bank group reflect a number
of estimates and assumptions including, but not limited to, future production
from the Company's proved properties, risk factors for proved reserves,
projected oil and gas prices, future operating and development costs, and
interest rates. Changes in such estimates and assumptions can significantly
impact the size of the borrowing base established by the banks. Because these
factors will be influenced by future events, which cannot be forecast with
certitude, the Company cannot predict what level of borrowing base will be
established at any future determination date. The provision for Facility B
was intended, in part, to provide short-term funds to develop the Company's
proved undeveloped and proved developed nonproducing reserves in the Gulf of
Mexico. It is anticipated that funds drawn under Facility B will be retired
through expansion of Facility A, if the Company's reserve values are
sufficiently increased, or that Facility B will be repaid from cash flows or
proceeds from the sale of assets or securities. At May 7, 1999, $90 million
was outstanding under Facility A and $8 million was outstanding under
Facility B.
Positive or negative changes in the borrowing base during 1999 could impact
the level of the Company's capital expenditures during the year. Increases,
supported by performance of the Company's properties,
16
<PAGE>
drilling results, and/or higher oil and gas prices, could improve the
Company's ability to grow. Decreases would adversely affect the Company's
liquidity and capital resources, potentially resulting in a reduction of
planned capital expenditures or the sale of assets or securities.
CAPITAL EXPENDITURES
Since the beginning of 1996, Basin has focused its exploration activities in
the shallow waters of the Gulf of Mexico, primarily off the coast of
Louisiana. Recently, the Company began to direct a small portion of its
exploration budget toward onshore opportunities, and it pursues acquisition,
development, and exploitation opportunities in the vicinity of the Company's
Gulf of Mexico exploration operations, in the Rocky Mountain region where
Basin has an existing base of proved reserves and producing wells, and in
certain other major domestic producing basins where the Company believes
significant upside potential exists. The Company's capital expenditures are
generally discretionary and activity levels are determined by a number of
factors, including oil and gas prices, availability of funds, quantity and
character of identified investment projects, availability of service
providers, and competition.
The Company currently estimates that its capital expenditures for exploration
and development in 1999 will be approximately $65 million, subject to
potential increase for proceeds from asset sales. This budget primarily
provides for: development of seven Gulf of Mexico properties with one or more
discovery wells yet to commence sustained production as of the end of 1998;
investments in seismic data and prospect leaseholds; participation in
approximately six net (13 to 15 gross) exploratory wells in the Gulf of
Mexico; participation in a small number of onshore exploration opportunities;
development of projected 1999 prospect discoveries; and continued
exploitation of the Company's other offshore and onshore properties. Although
several locations for planned 1999 exploratory drilling have been identified,
a significant portion of the 1999 exploration budget is currently
unallocated, pending acquisition of drilling partners and formation of joint
ventures to conduct exploratory operations. The smaller budget in 1999,
compared to actual expenditures in 1998, is not expected to require a
significant reduction in drilling activity because of a planned substantial
reduction in acquisitions of exploratory leaseholds in 1999 and benefits
expected to be realized from the substantial decline in service sector costs
during the past year. The reduced budget for exploratory leaseholds reflects
the unusually large investment made by the Company in 1998 to initially
establish a multi-year inventory of drilling prospects. New investments
planned for 1999 will seek to approximately maintain this inventory level
rather than significantly expand it. The Company also intends to pursue
acquisitions of properties with proved and probable reserves as an integral
part of its overall business strategy, with the expectation that these
efforts will result in significant investment activity over time. At this
time, no portion of the Company's 1999 budget has been specifically allocated
for acquisitions of proved properties. If such a transaction is executed, it
will likely require a re-allocation of budget from other planned activities
and/or external financing.
During the first quarter of 1999, the Company's accrual-basis capital
expenditures totaled approximately $22.5 million. Such investments were
primarily for development of several GOM properties on which discovery wells
were drilled during the prior year, participation in drilling five (2.5 net)
GOM wells, related completion costs on two (0.8 net) of these wells, and
acquisitions of additional GOM three-dimensional seismic data and leasehold
interests. The Company also submitted deposits totaling $0.6 million related
to five apparent winning bids aggregating $3.0 million made at the March 1999
Central Gulf of Mexico lease sale. Should the Minerals Management Service
approve all five of these high bids, the Company will owe the remaining 80%
of the respective bid amounts, or an additional total of $2.4 million. Such
amounts are provided for within the Company's budget for exploration and
development activities in the current year.
17
<PAGE>
The amount and allocation of future capital expenditures will depend on a
number of factors that are not entirely within the Company's control or
ability to forecast, including drilling results, scheduling of activities by
other operators, availability of service providers, success in acquiring
prospect leaseholds, and success in consummating acquisitions of proved
properties. The Company's planned capital expenditures are also based on
estimates regarding availability of capital that depend on assumptions and
estimates regarding production, oil and gas prices, and borrowing base
re-determinations under the Company's Credit Agreement. Due to these
uncertainties, and other matters described under "Forward Looking
Statements", actual capital expenditures may vary significantly from current
expectations.
Should the Company seek to increase its capital expenditure budget for 1999
to respond to drilling opportunities that it deems exceptional, to fund
development of a greater number or larger-sized exploratory successes than
assumed, or for acquisitions of proved and probable reserves or prospect
leaseholds, the Company may consider raising additional capital through
issuance of debt and/or equity securities. The Company may also seek
additional debt or equity financing in the absence of a specific planned
increase in capital expenditures, in order to increase financial flexibility
to capitalize on future opportunities.
YEAR 2000 READINESS DISCLOSURE AND STATEMENT
Readers are cautioned that the forward-looking statements contained in the
following Year 2000 discussion should be read in conjunction with the
Company's disclosures under the heading "Forward Looking Statements" in this
report.
Year 2000 issues result from the inability of many computer programs to
accurately calculate, store or use a date subsequent to December 31, 1999.
The date can be erroneously interpreted in a number of different ways;
typically the year 2000 is interpreted as the year 1900.This could result in
a system failure or miscalculations causing disruptions of or errors in
operations. Systems potentially affected include not only information
technology ("IT") systems -- computer systems controlling a company's
accounting, land, operations, seismic processing, and other specialized
functions -- but also non-IT systems controlled by embedded chips, which
include many common and specialized machines and support systems. The
effects of the Year 2000 problem can be exacerbated by the interdependence of
computer and telecommunications systems in the United States and throughout
the world. This interdependence can affect the Company and the parties with
whom it does business.
STATE OF READINESS. The Company has created an internal committee to assess
the Company's Year 2000 readiness and to lead its remediation efforts. The
committee is composed of the general counsel, chief financial officer,
controller, and manager of information systems. The committee's objective is
to prevent loss or impairment of those functions material to the Company's
operations and business continuity or to avoid potential liability to third
parties. At the direction of the committee, department heads and managers
have assessed and remediated the Company's IT and non-IT systems, and have
communicated with the Company's business partners regarding the status of
their assessment and remediation efforts, with the results summarized below.
The Company has completed an assessment of its IT systems to determine
whether they are Year 2000 compliant. The licensors of both the Company's
core financial, land and operations software system and its underlying
operating system have certified that such software is Year 2000 compliant.
The Company's Gulf of Mexico seismic data interpretation software system is
not currently Year 2000 compliant, but the
18
<PAGE>
Company has begun an upgrade of that system with software which the licensor
has represented will be compliant. The Company is also upgrading its
reservoir economics software to make it Year 2000 compliant. The Company
expects the upgrade and testing of these software systems to be completed by
July 1999. Additionally, the Company has assessed other less critical IT
systems and believes them to be compliant.
The Company also relies on non-IT systems, such as office telephones,
facsimile machines, HVAC systems and elevators in its leased offices,
security systems, and automated measuring equipment on platforms and other
production facilities, which may have embedded technology such as
micro-controllers. Department heads and managers have identified those
non-IT systems which may be susceptible to failure or impairment by reason of
Year 2000 problems and which are potentially critical to the Company's
operations and business continuity. Based on that review, the Company has
sent written inquiries to the suppliers of those systems to determine their
Year 2000 compliance. The vendors of the Company's communications systems
and the property managers of the buildings in which the Company's Houston and
Denver offices are situated have certified their systems to be Year 2000
compliant. The Company is still receiving and analyzing responses from
vendors of those non-IT systems that may affect the Company's production
operations. The operations department will follow up those inquiries with
telephone interviews to assess the status of such systems. Assessment and
remediation of non-IT systems should be completed by September 1999.
The Company has sent written inquiries to its significant suppliers,
customers, banks, government agencies, benefit plan providers, and others
with whom the Company has significant business relationships to determine the
extent to which the Company is vulnerable to those third parties' failure to
correct their own Year 2000 issues. To date, the Company has not received
definitive responses from many of these entities and therefore cannot assess
whether they are Year 2000 compliant or how their failure to be compliant
would affect the Company. Those third parties who have responded have
generally indicated that they are either Year 2000 compliant or expect to be
compliant. Department heads and managers have compiled a list of critical
third parties to whom telephone follow-up will be made. For Gulf of Mexico
operations, these include representative vendors and suppliers who could
supply necessary goods and services to maintain the Company's production
operations and continue any ongoing or planned drilling activities. The
Company expects to have this follow-up inquiry completed by July 1999 and
will utilize those vendors and suppliers providing adequate assurances
regarding their compliance.
ESTIMATED COMPLIANCE COSTS. The Company has relied primarily on its internal
staff to assess its current Year 2000 readiness and does not anticipate
extensive use of external resources to complete its assessment or
remediation. The Company has not separately quantified its costs of internal
resources on this project but does not expect that it will incur material
costs in remediating its IT systems to be Year 2000 compliant. Costs incurred
for the purchase of new software and hardware are capitalized and all other
costs are expensed as incurred. The Company has not incurred, and does not
anticipate that it will incur, costs for external resources in excess of
$100,000 relating to the assessment and remediation of Year 2000 issues. That
estimate does not include the cost of remediating problems caused by
third-party vendors, customers, or other business partners, which the Company
will not be able to estimate until the extent, if any, of their Year 2000
non-compliance is known.
RISKS OF NON-COMPLIANCE AND CONTINGENCY PLANS. As indicated above, the only
critical IT systems which the Company believes are not yet Year 2000
compliant are its seismic data interpretation and reservoir economics
systems, which should be compliant by July 1999. Accordingly, the Company
does
19
<PAGE>
not expect Year 2000 issues to cause its IT systems to have any material
adverse impact on its business, operations or financial condition. The
Company believes that the potential impact, if any, of its non-critical IT
systems not being Year 2000 compliant will at most require employees to
manually complete otherwise automated tasks or calculations and should not
impact the Company's ability to continue exploration, drilling, production or
sales activities. The Company is not able to predict at this time what the
impact could be of non-IT system failures but does not believe that there
will be a material disruption of the Company's operations.
Until the Company has completed its inquiries to third parties, it will not
be able to assess the potential impact of their failure to be Year 2000
compliant on the Company's operations, business, or financial condition. The
most reasonably likely "worst case" impacts could be impairment of the
Company's ability to deliver its production to, or receive payment from,
third parties gathering and/or purchasing the Company's production from
affected facilities, impairment of the ability of third-party suppliers or
service companies to provide needed materials or services to the Company's
planned or ongoing operations, thereby necessitating deferral or shut-in of
exploration, development or production operations, and the inability of the
Company to execute financial transactions with its banks or other third
parties whose systems fail or misfunction. The Company currently has no
reason to believe that any of these contingencies will occur or that its
principal vendors, customers, and business partners will not be Year 2000
compliant.
The Company does not currently have a contingency plan under development or
in place to address these potential problems. The Company does intend to
develop contingency plans in response to testing its IT and non-IT systems
and in response to the results of its third-party inquiries. These
contingency plans may include installing back-up computer systems or
equipment, temporarily replacing systems or equipment with manual processes,
and identifying alternate suppliers, service companies and purchasers. The
Company expects these plans to be complete by October 1999.
Basin's Year 2000 program is a continuing process that may result in changes
to cost estimates and schedules as testing and business partner assessment
progresses. Unexpected Year 2000 compliance problems of either the Company
or its vendors, customers, service providers, or other entities with whom it
does business could have a material adverse impact on the Company's business,
financial condition or operating results.
20
<PAGE>
FORWARD LOOKING STATEMENTS
This Quarterly Report on Form 10-Q contains statements that are not
historical facts but are forward-looking statements that involve risks and
uncertainties that could cause actual results to differ from projected
results. Such statements address activities, events or developments that the
Company expects, believes, projects, intends, estimates, plans or anticipates
will, should, could or may occur, including such matters as:
- - amount and nature of capital expenditures,
- - drilling of wells,
- - estimated reserves,
- - timing and amount of future production of oil and gas,
- - business strategies,
- - operating costs and other expenses,
- - cash flow and anticipated liquidity,
- - prospect development and property acquisitions,
- - marketing of oil and gas, and
- - Year 2000 compliance activities.
Although the Company believes that the expectations reflected in the
forward-looking statements are reasonable, we cannot assure you that any of
these expectations will prove correct or that we will take any actions that
may have been planned. Factors that could cause actual results to differ
materially are described in the "Management's Discussion and Analysis of
Financial Condition and Results of Operations" section of this report and
also include, among others:
- - general economic conditions,
- - oil and gas price volatility,
- - the Company's ability to find, acquire, market, develop and produce new
properties,
- - the risks associated with acquisitions,
- - the risks associated with exploration,
- - operating hazards attendant to the oil and gas business,
- - downhole drilling and completion risks that are generally not
recoverable from third parties or insurance
- - uncertainties in the estimation of proved reserves and in the
projection of future rates of production and timing of development
expenditures,
- - potential mechanical failure or underperformance of individually
significant productive wells,
- - the strength and financial resources of the Company's competitors,
- - the Company's ability to find and retain skilled personnel,
- - climatic conditions,
- - availability of capital,
- - availability and cost of material and equipment,
- - delays in anticipated start-up dates,
- - environmental risks,
- - actions or inactions of third-party operators of the Company's
properties, regulatory developments, and
- - third-party Year 2000 compliance actions.
21
<PAGE>
All written and oral forward-looking statements attributable to the Company
or persons acting on its behalf are qualified in their entirety by the
Cautionary Disclosures. The Company disclaims any obligation to update or
revise any forward-looking statement in light of actual results or future
events.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
The Company's exposure to interest rate risk and commodity price risk is
discussed in Management's Discussion and Analysis of Financial Condition and
Results of Operations under the headings "Operating Environment",
"Liquidity and Capital Resources - Marketing and Hedging Transactions" and
"Liquidity and Capital Resources - Credit Facility". The Company has no
exposure to foreign currency exchange rate risks or to any other market risks.
22
<PAGE>
BASIN EXPLORATION, INC. AND SUBSIDIARIES
PART II OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBITS
------ -----------------------
<S> <C>
2.1 Agreement and Plan of Merger between Sterling Energy
Corporation, Basin Energy, Inc. and Basin Exploration, Inc.
dated October 13, 1994(5)
2.2 Plan of Merger between Basin Sterling, Inc. and Basin
Exploration, Inc. dated November 22, 1994(5)
2.3 Plan of Merger between Basin Operating Company and Basin
Exploration, Inc. dated December 14, 1994.(7)
3.1 Restated Certificate of Incorporation of Basin.(2)
3.2 Restated Bylaws of Basin.(2)
4.1 Common Stock Certificate of Basin.(2)
10.1 Equity Incentive Plan as amended May 5, 1998.14 10.3 Key
Employee Participation Plan.(14)
10.3 Key Employee Participation Plan.(2)
10.4 Employment Agreement dated March 31, 1992 by and between Basin
and Michael S. Smith.(3)
10.5 Gulf Coast Geoscientist Overriding Royalty Interest Plan dated
November 30, 1995.(9)
10.6 Form of Rights Agreement dated as of February 24, 1996,
between Basin Exploration, Inc. and Corporate Stock Transfer,
Inc. as Rights Agent.(8)
10.7 Performance Shares Plan approved February 4, 1997.(10)
10.8 Change of Control Employment Agreement dated October 13, 1995
between Basin Exploration, Inc. and Howard L. Boigon.(9)
10.9 Employment Agreement dated August 28, 1995 between Basin
Exploration, Inc. and Samuel D. Winegrad.(9)
10.10 Employment Agreement dated June 28, 1995 between Basin
Exploration, Inc. and Neil L. Stenbuck.(9)
10.11 Employment Agreement dated November 10, 1995 between Basin
Exploration, Inc. and David A. Pustka.(9)
10.12 Employment Agreement dated February 23, 1996 between Basin
Exploration, Inc. and Thomas J. Corley.(10)
10.13 Assignment and Assumption of Lease dated December 18, 1995 by
and between Team, Inc., as original Tenant, Basin Exploration,
Inc., as New Tenant, and FC Tower Property Partners, LP, as
Landlord.(8)
10.16 Lease of Office Space dated September 25, 1992, between
Brookfield Republic Inc. and Basin Operating Company, as
amended(4)+
10.17 First Lease of Additional Office Space dated as of December 1,
1994, between Brookfield Republic, Inc. and Basin Operating
Company.(6)+
10.18 Purchase and Sale Agreement dated February 13, 1997, between
Hall-Houston Oil Company et al as Sellers and Basin
Exploration, Inc. as Buyer.(10)+
10.19 First Amendment of Amended and Restated Credit Agreement dated
August 6, 1996 between the Company and Colorado National Bank,
Union Bank of California, N.A. and NationsBank of Texas, N.A.
dated June 11, 1997(11)
10.20 Order of the United States Bankruptcy Court for the Southern
District of Texas Corpus Christi Division, dated November 18,
1997, with exhibits, including the Agreement of Purchase and
Sale.(12)
10.21 Second Amendment of Amended and Restated Credit Agreement
dated August 6, 1996 between the Company and Colorado National
Bank, Union Bank of California, N.A. and NationsBank of Texas,
N.A. dated November 1, 1997(13)
10.22 Third Amendment of Amended and Restated Credit Agreement dated
August 6, 1996 between the Company and U.S. Bank National
Association, Union Bank of California, N.A. and NationsBank of
Texas, N.A. dated April 30, 1998(14)
23
<PAGE>
10.23 Fourth Amendment of Amended and Restated Credit Agreement
dated August 6, 1996 between the Company and U.S. Bank
National Association, Union Bank of California, N.A. and
Nationsbank, N.A., dated August 20, 1998(15)
10.24 Amended and Restated Credit Agreement dated January 1, 1999
among the Company and Nationsbank, N.A., U.S. National
Association and Union Bank of California, N.A.(16)
10.25 Employment Agreement dated January 28, 1999, between Basin
Exploration, Inc. and Patrick A. Jackson.(16)
10.26 Employment Agreement dated February 1, 1999, between Basin
Exploration, Inc. and David A. Pustka.(16)
27 Financial Data Schedule(1)
</TABLE>
(1) Filed herewith.
(2) Filed as an Exhibit to Basin's Registration Statement on Form
S-1 as filed on March 17, 1992, Registration No. 33-46486, and
incorporated herein by reference.
(3) Filed as an Exhibit to Amendment No. 1 to Basin's Registration
Statement on Form S-1 as filed on April 21, 1992, Registration
No. 33-46486, and incorporated herein by reference.
(4) Filed as an Exhibit to Basin's Registration Statement on Form
S-1 as filed on October 25, 1993, Registration No. 33-70802, and
incorporated herein by reference.
(5) Filed as an Exhibit to Form 8-K filed on December 10, 1994, and
incorporated herein by reference.
(6) Filed as an Exhibit to Form 10-K/A-1 filed on June 26, 1995 and
incorporated herein by reference.
(7) Filed as an Exhibit to Form 10-K filed on March 28, 1995, and
incorporated herein by reference.
(8) Filed as an Exhibit to Form 8-K filed on February 26, 1996, and
incorporated herein by reference.
(9) Filed as an Exhibit to Form 10-K filed on March 28, 1996, and
incorporated herein by reference.
(10) Filed as an Exhibit to Form 10-K filed on March 31, 1997, and
incorporated herein by reference.
(11) Filed as an Exhibit to Form 10-Q filed on August 12, 1997, and
incorporated herein by reference.
(12) Filed as an Exhibit to Form 8-K filed on December 11, 1997, and
incorporated herein by reference.
(13) Filed as an Exhibit to Form 10-K filed on March 31, 1998, and
incorporated herein by reference.
(14) Filed as an Exhibit to Form 10-Q filed on May 14, 1998, and
incorporated herein by reference.
(15) Filed as an Exhibit to Form 10-Q filed on November 13, 1998, and
incorporated herein by reference.
(16) Filed as an Exhibit to Form 10-K filed on March 30, 1999, and
incorporated herein by reference.
+ Confidential treatment has been granted for portions of these Exhibits.
(b) Reports on Form 8-K
None.
24
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
BASIN EXPLORATION, INC.
-----------------------
(Registrant)
Date: May 17, 1999 By:/s/ Neil L. Stenbuck
--------------------
Neil L. Stenbuck
Chief Financial Officer
Date: May 17, 1999 By:/s/ James A Tuell
-----------------
James A. Tuell
Controller
Chief Accounting Officer
25
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
COMPANY'S UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS FOR THE THREE MONTHS ENDED
MARCH 31, 1999 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> MAR-31-1999
<CASH> 20
<SECURITIES> 0
<RECEIVABLES> 9,227
<ALLOWANCES> 0
<INVENTORY> 206
<CURRENT-ASSETS> 13,038
<PP&E> 327,576
<DEPRECIATION> 126,888
<TOTAL-ASSETS> 214,843
<CURRENT-LIABILITIES> 29,495
<BONDS> 91,000
0
0
<COMMON> 142
<OTHER-SE> 94,161
<TOTAL-LIABILITY-AND-EQUITY> 214,843
<SALES> 13,042
<TOTAL-REVENUES> 13,055
<CGS> 2,531
<TOTAL-COSTS> 12,504
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 949
<INCOME-PRETAX> (398)
<INCOME-TAX> 0
<INCOME-CONTINUING> (398)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (398)
<EPS-PRIMARY> (.03)
<EPS-DILUTED> (.03)
</TABLE>
