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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
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(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998
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:
BRIGHAM EXPLORATION COMPANY
(Exact name of Registrant as Specified in its Charter)
DELAWARE 75-2692967
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
6300 BRIDGE POINT PARKWAY
BUILDING 2, SUITE 500 78730
AUSTIN, TEXAS (Zip Code)
(Address of principal executive offices)
(512) 427-3300
(Registrant's telephone number, including area code)
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Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
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None None
Securities registered pursuant to Section 12(g) of the Act:
COMMON STOCK, $.01 PAR VALUE
(Title of Class)
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
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Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
As of March 26, 1999, the Registrant had outstanding 13,306,206 shares of
Common Stock. The aggregate market value of the Common Stock held by
non-affiliates of the Registrant, based upon the closing sale price of the
Common Stock on March 26, 1999, as reported on The Nasdaq Stock Market(sm), was
approximately $18 million.
Pursuant to Rule 12b-25 under the Act, (1) combined financial statements of
the Registrant's subsidiaries whose securities are pledged as collateral for the
Registrant's Senior Subordinated Secured Notes and (2) certain exhibits have
been omitted from this Form 10-K.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrant's 1999 Annual
Meeting of Stockholders to be held on May 13, 1999, are incorporated by
reference in Part III of this Form 10-K. Such definitive proxy statement will be
filed with the Securities and Exchange Commission not later than 120 days
subsequent to December 31, 1998.
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TABLE OF CONTENTS
PAGE
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PART I
ITEM 1. BUSINESS.......................................................................1
ITEM 2. PROPERTIES.....................................................................9
ITEM 3. LEGAL PROCEEDINGS.............................................................18
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS............................18
EXECUTIVE OFFICERS OF THE REGISTRANT.......................................................19
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS...........................................................20
ITEM 6. SELECTED FINANCIAL DATA.......................................................21
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS.....................................................22
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK....................39
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA...................................39
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE......................................................39
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT............................40
ITEM 11. EXECUTIVE COMPENSATION........................................................40
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT....................................................................40
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS..........................40
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K...............41
GLOSSARY OF OIL AND GAS TERMS..............................................................47
SIGNATURES.................................................................................51
INDEX TO FINANCIAL STATEMENTS............................................................F1-1
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BRIGHAM EXPLORATION COMPANY
1998 ANNUAL REPORT ON FORM 10-K
PART I
ITEM 1. BUSINESS
OVERVIEW
Brigham Exploration Company ("Brigham" or the "Company") is an independent
exploration and production company that applies 3-D seismic imaging and other
advanced technologies to systematically explore and develop onshore oil and
natural gas provinces in the United States. The Company focuses its 3-D seismic
activity in provinces where it believes 3-D technology may be effectively
applied to generate relatively large potential reserve volumes per well and per
field, high potential production rates and multiple producing objectives. The
Company's exploration activities are concentrated primarily in three core
provinces: the Anadarko Basin of western Oklahoma and the Texas Panhandle; the
onshore Gulf Coast of south Texas and, to a lesser extent, the transition zone
of Louisiana; and West Texas.
The Company pioneered the acquisition of large scale onshore 3-D seismic
surveys for exploration, obtaining extensive 3-D seismic data and experience in
capturing undiscovered oil and natural gas reserves. As of December 31, 1998,
Brigham has acquired 5,236 square miles (3.3 million acres) of 3-D seismic data
and has identified an estimated 1,140 potential drilling locations, of which the
Company has drilled 442. The Company generates most of its exploratory projects
and, therefore, has the ability to retain a sizeable working interest to the
extent that it decides not to place interests with industry participants.
From inception in 1990 through 1998, Brigham has drilled 378 exploratory
and 64 development wells on its 3-D generated prospects with an aggregate 64%
success rate and an average working interest of 29%. As of December 31, 1998,
the Company has added 114 Bcfe of net proved reserves to its reserve base,
approximately 92 net Bcfe of which were discovered by Brigham through its
systematic 3-D exploration drilling activities at an average net drilling cost
of $0.82 per Mcfe. The Company's estimated net proved reserves as of December
31, 1998 were 97.8 Bcfe having an aggregate Present Value of Future Net Revenues
of $81.7 million, compared to estimated net proved reserves as of December 31,
1996 of 21.9 Bcfe having an aggregate Present Value of Future Net Revenues of
$44.5 million. The Company's net proved reserve volumes at December 31, 1998 are
73% natural gas and 57% proved developed reserves.
BUSINESS STRATEGY
Brigham's principal objective and business strategy is to achieve superior
growth in shareholder value through the application of its systematic
exploration approach, which emphasizes the integrated use of 3-D seismic imaging
and other advanced technologies to reduce drilling risks and finding costs.
Since its inception in 1990, the Company has achieved rapid growth in its
acquisition of 3-D seismic data, identification of potential drilling locations,
discovery of proved reserves and production volumes.
Brigham completed its initial public offering of common stock in May 1997,
raising approximately $24 million to fund the Company's accelerated 3-D seismic
acquisition and exploration drilling activities. Key elements of the Company's
long-term growth strategy at its initial public offering and continuing today
include: (i) acquiring 3-D seismic data in proven producing trends to identify
and capture potential drilling locations; (ii) retaining significant working
interests in its exploration projects to capture a greater share of the reserves
that the Company discovers; (iii) identifying higher potential, higher impact
prospects; and (iv) monetizing the value of its 3-D seismic investments by
drilling its inventory of 3-D seismic delineated locations.
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Since its initial public offering in early 1997, Brigham has been effective
in the implementation of its long-term growth strategy. During 1997 and 1998,
the Company acquired 2,475 square miles of 3-D seismic data at an average
working interest of 73%, which nearly doubled its inventory of gross onshore 3-D
seismic data to 5,236 square miles as compared to year-end 1996 and increased
its net onshore 3-D seismic data in inventory more than three-fold from 780
square miles at year-end 1996 to 2,590 square miles at year-end 1998. Brigham's
overall level of 3-D seismic acquisition during the past two years represents
the most active in the Company's history, and 90% of the recently acquired data
is located in Brigham's higher potential Anadarko Basin and Gulf Coast provinces
where it has achieved historically lower finding costs for drilling than in its
West Texas province. As a result of these significant investments in 3-D seismic
acquisition and interpretation in proven natural gas producing trends, the
Company believes it has assembled a significant competitive knowledge base and
strategic position in each of its two active exploration provinces. Brigham
further believes it has captured a high quality inventory of 3-D delineated
potential drilling locations that can be monetized through the drillbit at
profitable finding costs over the next several years, thereby providing
opportunities for future reserve, production and cash flow growth.
Brigham has substantially reduced its planned capital expenditure budget
for 1999 and has undertaken a number of strategic initiatives in an effort to
improve and preserve its capital liquidity in the current environment. While the
Company remains focused on its long-term growth objectives and the continuation
of its established business model for 3-D seismic-based exploration, Brigham has
adapted its business strategy in the near-term in an effort to maximize value
for its shareholders on a long-term basis through the implementation of the
following principal strategic initiatives: (i) focusing all of the Company's
planned exploration efforts in 1999 toward the drilling of its highest- grade
3-D prospects identified in its Anadarko Basin and Gulf Coast projects,
concentrated primarily in trends where Brigham has achieved exploration success,
(ii) eliminating substantially all planned seismic and land expenditures for new
projects until its capital resources can support such additional activity, (iii)
seeking to divest certain producing natural gas and oil properties in an effort
to raise capital to reduce debt borrowings and to redirect capital to drilling
projects that have the potential to generate higher investment returns, (iv)
restructuring its outstanding senior and subordinated debt agreements to provide
the Company with flexibility needed to preserve cash flow to fund its expected
near-term exploration activities, (v) implementing an overhead reduction plan to
reduce general and administrative expenses, and (vi) evaluating opportunities to
raise additional equity capital either through the sales of interests in certain
of its seismic projects or the issuance of equity securities. The Company
believes that the successful execution of these strategic initiatives will
provide Brigham with sufficient capital resources to execute its planned 1999
exploration program and position the Company to realize the significant value it
believes it has captured in its inventory of 3-D seismic projects and delineated
drilling locations. See "Item 7. Management's Discussion and Analysis of
Financial Condition and Operating Results -- Liquidity" and "-- Capital
Resources."
EXPLORATION AND OPERATING APPROACH
The Company has acquired 3-D seismic data covering 5,236 square miles (3.3
million acres) in over 20 geologic trends in seven basins and seven states.
Through this activity, the Company has developed expertise in the selection of
geologic trends that are suitable for 3-D seismic exploration. Brigham uses
experience that it gains within a trend to enhance the quality of subsequent
projects in the same trend and other analogous trends, contributing to lower
finding and development costs, compressed project cycle times and increased
project rates of return.
The Company typically acquires 3-D seismic data in and around existing
production where the Company can benefit from the imaging of producing analogs.
These 3-D defined analogs, combined with the Company's experience in drilling
442 wells, provide the Company with a knowledge base to evaluate other potential
geologic trends, 3-D seismic projects within trends and 3-D delineated potential
drilling locations. The Company's knowledge base assists in identifying geologic
trends where Brigham believes it can find and develop economic volumes of oil
and natural gas.
The Company has experience exploring with 3-D seismic in a wide range of
reservoir types and geologic trapping styles, both stratigraphic and structural
(including reefs, salt domes, channel sands, complex faulted and fractured
reservoirs and pinchout plays). The Company seeks to supplement its knowledge
base with the best local geologic expertise available for a particular geologic
trend. In addition, the Company typically acquires digital data bases for
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integration on the Company's CAEX workstations, including digital land grids,
well information, log curves, production information, geologic studies, geologic
top data bases and existing 2-D seismic data.
The Company uses its knowledge base, local geological expertise and digital
data bases integrated with 3-D seismic to create maps of producing and
potentially productive reservoirs. The Company believes its 3-D generated maps
are more accurate than previous reservoir maps (which generally were based on
subsurface geological information and 2-D seismic surveys), enabling the Company
to more precisely evaluate recoverable reserves and the economic feasibility of
projects and drilling locations.
Brigham acquires most of its raw 3-D seismic data using seismic acquisition
vendors on either a proprietary basis or through alliances affording it the
exclusive right to interpret and use data for extended periods of time. In
addition, the Company participates in non-proprietary group shoots of 3-D data
when it believes the expected full cycle project economics are justified. In its
proprietary acquisitions and alliances, Brigham selects the sites of projects,
primarily guided by its knowledge and experience in the core provinces it
explores; establishes and monitors the seismic parameters of each project for
which data is shot; and typically selects the equipment that will be used. Data
is generally priced on the basis of square miles shot. See "Item 1. Business --
Industry Alliances."
EXPLORATION STAFF
Over the last eight years the Company has assembled an exploration staff
that includes ten geophysicists, ten geologists, four petroleum engineers, five
computer applications specialists, five geophysical/geological/engineering
technicians, six landmen and six lease and division order analysts. Brigham's
ten geophysicists have different but complementary backgrounds, and their
diversity of experience in varied geological and geophysical settings, combined
with various technical specializations (from hardware and systems to software
and seismic data processing), provide the Company with valuable technical
intellectual resources. The Company's team of explorationists has over 310 years
of exploration experience and more than 85 years of 3-D CAEX workstation
experience, most of which was acquired at Brigham and various major and large
independent oil companies. Occasionally, the Company complements and leverages
its exploration staff by seeking out alliances or retainer relationships with
geologists having extensive experience in a particular area of interest.
3-D SEISMIC TECHNOLOGY
The Company's strategy is to use 3-D seismic and other advanced
technologies, including CAEX, to systematically explore and develop domestic
onshore oil and natural gas provinces. In general, 3-D seismic is the process of
acquiring seismic data along multiple lines and grids. The primary advantage of
3-D seismic over 2-D seismic is that it provides information with respect to
multiple horizontal and vertical points within a geologic formation instead of
information on a single vertical line or multiple vertical lines within the
formation. Acquiring larger amounts of data relating to a geologic formation
allows a user to better correlate the data and, in some cases, obtain a greater
understanding and image of the formation. Although it is impossible to predict
with certainty the specific configuration or composition of any underground
geologic formation, the use of 3-D seismic data provides clearer and more
accurate projected images of complex geologic formations, which can assist a
user in evaluating whether to drill for oil and natural gas reserves. If a
decision to drill is made, 3-D seismic data can also help in determining the
optimal location to drill.
CAEX is the process of accumulating and analyzing the various seismic,
production and other data obtained relating to a geographic area. In general,
CAEX involves accumulating various 2-D and 3-D seismic data with respect to a
potential drilling location, correlating that data with historical well control
and production data from similar properties and analyzing the available data
through computer programs and modeling techniques to project the likely geologic
composition of a potential drilling location and potential locations of
undiscovered oil and natural gas reserves. This process relies on a comparison
of data with respect to the potential drilling location and historical data with
respect to the density and sonic characteristics of different types of rock
formations, hydrocarbons and other subsurface minerals, resulting in a projected
three dimensional image of the subsurface. This modeling is performed through
the use of advanced interactive computer workstations and various combinations
of available computer programs that have been developed solely for this
application.
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Brigham has invested extensively in the advanced computer hardware and
software necessary for 3-D seismic exploration. The Company has both Landmark
and Geoquest CAEX workstations. This workstation flexibility provides the
Company the opportunity to interpret a project on the particular CAEX
workstation that it believes is best suited for defining those particular
geologic objectives. Brigham's explorationists can access a diverse software
tool kit including SeisWorks, StratWorks, EarthCube, OpenVision, Open Explorer,
ZAP, Zmap+, ARIES, SynTool, Poststack, TDQ, AutoPix, MapView, GeoViz, Voxels,
SynView, CSA (Computed Seismic Attributes), Surface Slice, Hampson -- Russell
AVO Analysis and Modeling and ZEH Graphics CGMage Builder (graphics montage
tool).
The Company believes that its use of 3-D seismic technology provides it
with a number of benefits in the exploration, delineation and development
process that are not generally available to those who only use 2-D seismic data
and conventional processing methods. In particular, the Company believes that it
obtains clearer and more accurate projected images of underground formations
through computer modeling, and is therefore better able to identify potential
locations of hydrocarbon accumulations based on the characteristics of the
formations and analogies made with nearby fields and formations where
hydrocarbons have been found. This enhanced data has been used to assist the
Company in eliminating potential drilling locations that might otherwise have
been drilled had the Company relied solely on 2-D seismic data. This data has
also been used to assist the Company in attempting to identify the most
desirable location for the wellbore to increase the prospects of a successful
exploratory or development well and production from the reservoir.
INDUSTRY ALLIANCES
Veritas Anadarko Basin Acquisition Alliances. Pursuant to certain alliances
with Veritas DGC Land Ltd. ("Veritas"), Brigham has acquired approximately 1,460
square miles of 3-D seismic in the Anadarko Basin through December 31, 1998 and
has agreed to acquire from 165 to 265 additional square miles of data to be
divided among individual projects in that province. In exchange for the
Company's commitment to Veritas, the Company and its assignees only pay a
portion of the 3-D seismic acquisition costs as the data is acquired. As the
Company leases acreage or drills wells, it pays Veritas the balance of the
deferred costs in the form of leasing and drilling fees until such deferred
costs are repaid or until certain time periods have occurred. In addition, in
the event that the outstanding balance of deferred seismic acquisition costs
exceeds certain threshold amounts, the Company must pre-pay part of the leasing
and drilling fees to cause the outstanding balance to fall below the current
threshold amount. These arrangements afford the Company access to 3-D seismic
acquisition in a compressed cycle time, providing the Company with significant
operational efficiencies.
In addition, Veritas Geoservices, Ltd. provides employees that maintain and
operate seismic data processing workstations in Brigham's offices. Supervised by
Brigham's geophysicists, the vendor's employees process most of the Company's
3-D seismic. The associated improvement in communication and integration, from
field data acquisition to processing, reduces project cycle times, and therefore
costs, while improving the quality of the data for Brigham's subsequent
interpretation.
Anadarko Basin Alliance I. The Company has entered into alliances with
Vintage Petroleum, Inc. ("Vintage") and Stephens Production Company ("Stephens")
which provided for their participation with Brigham in all of the projects that
the Company conducted within a 625 square mile 3-D seismic program that was
completed in 1997 with Veritas in the Anadarko Basin. Vintage and Stephens
incurred a disproportionate share of all pre-seismic and certain seismic costs
on all projects in the program. Net of the interests of Vintage and Stephens,
the Company holds a 37.5% interest in the program. The Company believes that
this leveraging of its costs was possible because of the expertise and knowledge
that the Company has developed, enabling the Company to build its revenue and
cash flow base at a time when it has been capital constrained.
Anadarko Basin Alliance II. Upon completion of data acquisition in its
Alliance I program, Brigham began acquiring 3-D seismic under a second alliance
with Veritas in the Anadarko Basin. From August 1997 through November 1998, the
Company acquired approximately 835 square miles of 3-D seismic under this
alliance with a 100% working interest. Pursuant to the terms of its acquisition
agreement with Veritas, Brigham ceased acquisition of 3-D seismic data in the
Alliance II program in early November 1998, and the Company will consider
acquiring the balance of the data contemplated in this program when it
determines that its capital resources are sufficient to incur such
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expenditures. The Company currently intends to retain a majority working
interest in its Alliance II seismic projects subsequent to the sale and
potential future sales of a portion of its working interests in certain of these
projects. See "-- Duke Project Financing."
Carry-to-Casing Point Programs. From 1996 through 1998, Brigham has entered
into annual agreements with certain industry parties to participate in all of
the wells drilled by the Company during the term of the agreement on a promoted
drilling cost basis. For example, in order to participate in wells drilled by
the Company between April 1, 1998 and March 31, 1999, Gasco Limited Partnership
("Gasco") agreed to fund 8% of the Company's drilling costs and 4% of its
completion costs for each well. In return, the Company agreed to assign to Gasco
an undivided 4% of the Company's interest in the leasehold allocated to the
production unit for each completed well. As a result, the Company pays for 92%
of costs attributable to its working interest to casing point, and 96% of its
completion costs, for 96% of its original working interest for each well funded
during the term of the agreement.
Brigham entered into a carry-to-casing point agreement in late 1998 with a
major drilling contractor to participate in four wells drilled by the Company.
Pursuant to the agreement, the drilling contractor agreed to fund 25% of the
Company's drilling costs and 12.5% of its completion costs for each of these
four wells. In return, the Company agreed to utilize the drilling contractor's
services for the drilling of the wells and to assign to the drilling contractor
an undivided 12.5% of the Company's interest in the leasehold allocated to the
production unit for each completed well. As a result, the Company pays for 75%
of costs attributable to its working interest to casing point, and 87.5% of its
completion costs, for 87.5% of its original working interest for each well
drilled under the agreement. Brigham is currently in discussions with the
drilling contractor to extend this arrangement to provide for the participation
in all of the wells spud by the Company over an annual term. However, there can
be no assurance that such an arrangement will be reached or that the terms of
any such arrangement will not differ from those in its prior agreements. The
Company believes that current industry conditions have provided it with the
opportunity to seek such arrangements with industry service providers to fund a
portion of its capital expenditures in exchange for service commitments with
such providers at competitive prices.
The Company believes that its carry-to-casing point agreements have been
beneficial because they have allowed the Company to leverage its working
interests in its properties by requiring it to bear a disproportionately smaller
share of drilling costs, thereby enhancing its returns on drilling capital
investments. Depending on future conditions, the Company may seek to enter into
similar types of arrangements with industry or financial participants. To the
extent that the Company does seek to enter into such future arrangements, the
terms of these arrangements, including the percentages of costs borne and
interests assigned, may vary from those in the Company's past and present
arrangements.
Duke Project Financing. In February 1999, the Company entered into a
project financing arrangement with Duke Energy Financial Services, Inc. ("Duke")
to fund the continued exploration of five projects covered by approximately 200
square miles of 3-D seismic data acquired in 1998 as part of its Anadarko Basin
Alliance II program. In this transaction, the Company conveyed 100% of its
working interest (land and seismic) in these project areas to a newly formed
limited liability company (the "Duke LLC") for total consideration of $10
million. The Company is the managing member of the Duke LLC with a 1% interest,
and Duke is the sole remaining member with a 99% interest. Pursuant to the terms
of the Duke LLC agreement, Brigham pays 100% of the drilling and completion
costs for all wells drilled by the Duke LLC within the designated project areas
in exchange for a 70% working interest in the wells (and their allocable
drilling and spacing units), with the remaining 30% working interest remaining
in the Duke LLC, subject in each instance to proportionate reduction by any
ownership rights held by third parties. Upon 100% project payout, the Company
has the right to back-in for 80% of the Duke LLC's working interest in all of
the then producing wells (and their allocable drilling and spacing units) and a
96% working interest in any wells (and their allocable drilling and spacing
units) drilled after payout within the designated project areas governed by the
Duke LLC agreement, thereby increasing the Company's effective working interest
in the Duke LLC wells from 70% to 94%. The Company believes this project
financing arrangement to be beneficial as it enabled Brigham to recoup
substantially all of its pre-seismic land and seismic data acquisition costs
incurred in these project areas and provided capital to drill the first six
wells within these projects.
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NATURAL GAS AND OIL MARKETING AND MAJOR CUSTOMERS
Most of the Company's natural gas and oil production is sold under price
sensitive or spot market contracts. The revenues generated by the Company's
operations are highly dependent upon the prices of and demand for natural gas
and oil. The price received by the Company for its natural gas and oil
production depends on numerous factors beyond the Company's control, including
seasonality, competition, the condition of the United States economy, foreign
imports, political conditions in other oil-producing and natural gas-producing
countries, the actions of the Organization of Petroleum Exporting Countries, and
domestic government regulation, legislation and policies. Decreases in the
prices of natural gas and oil could have an adverse effect on the carrying value
of the Company's proved reserves and the Company's revenues, profitability and
cash flow. Although the Company is not currently experiencing any significant
involuntary curtailment of its natural gas or oil production, market, economic
and regulatory factors may in the future materially affect the Company's ability
to sell its natural gas or oil production. See "Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations", "--Risk Factors
- -- Volatility of Natural Gas and Oil Prices" and "--Risk Factors --
Marketability of Production." For the year ended December 31, 1998, sales to
Highland Energy Company, Ward Petroleum Corporation, Lantern Petroleum
Corporation and Louis Dreyfus Natural Gas Corporation were approximately 25%,
15%, 11% and 11%, respectively, of the Company's natural gas and oil revenues.
Due to the availability of other markets and pipeline connections, the Company
does not believe that the loss of any single natural gas or oil customer would
have a material adverse effect on the Company's results of operations.
COMPETITION
The oil and gas industry is highly competitive in all of its phases. The
Company encounters competition from other oil and gas companies in all areas of
its operations, including the acquisition of seismic and leasing options and oil
and natural gas leases on properties. The Company's competitors include major
integrated oil and natural gas companies and numerous independent oil and
natural gas companies, individuals and drilling and income programs. Many of its
competitors are large, well established companies with substantially larger
operating staffs and greater capital resources than the Company's. Such
companies may be able to pay more for seismic and lease options on oil and
natural gas properties and exploratory prospects and to define, evaluate, bid
for and purchase a greater number of properties and prospects than the Company's
financial or human resources permit. The Company's ability to acquire additional
properties and to discover reserves in the future will be dependent upon its
ability to evaluate and select suitable properties and to consummate
transactions in a highly competitive environment. See "Item 7. Management's
Discussion and Analysis of Risk Factors -- Competition" and "-- Risk Factors --
Substantial Capital Requirements."
OPERATING HAZARDS AND UNINSURED RISKS
Drilling activities are subject to many risks, including the risk that no
commercially productive reservoirs will be encountered. There can be no
assurance that new wells drilled by the Company will be productive or that the
Company will recover all or any portion of its investment. Drilling for oil and
natural gas may involve unprofitable efforts, not only from dry wells, but also
from wells that are productive but do not produce sufficient net revenues to
return a profit after drilling, operating and other costs. The cost of drilling,
completing and operating wells is often uncertain. The Company's drilling
operations may be curtailed, delayed or canceled as a result of numerous
factors, many of which are beyond the Company's control, including title
problems, weather conditions, compliance with governmental requirements and
shortages or delays in the delivery of equipment and services. The Company's
future drilling activities may not be successful and, if unsuccessful, such
failure may have a material adverse effect on the Company's business, financial
condition or results of operations. See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Risk Factors --
Dependence on Exploratory Drilling Activities." In addition, use of 3-D seismic
technology requires greater pre-drilling expenditures than traditional drilling
strategies. Although the Company believes that its use of 3-D seismic technology
will increase the probability of drilling success, some unsuccessful wells are
likely, and there can be no assurance unsuccessful drilling efforts will not
have a material adverse effect on the Company's business, financial condition or
results of operations.
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The Company's operations are subject to hazards and risks inherent in
drilling for and producing and transporting oil and natural gas, such as fires,
natural disasters, explosions, encountering formations with abnormal pressures,
blowouts, cratering, pipeline ruptures and spills, any of which can result in
the loss of hydrocarbons, environmental pollution, personal injury claims and
other damage to properties of the Company and others. The Company maintains
insurance against some but not all of the risks described above. In particular,
the insurance maintained by the Company does not cover claims relating to
failure of title to oil and natural gas leases, trespass during 3-D survey
acquisition or surface change attributable to seismic operations, business
interruption or loss of revenues due to well failure. In certain circumstances
in which insurance is available the Company may not purchase it. The occurrence
of an event that is not covered, or not fully covered, by insurance could have a
material adverse effect on the Company's business, financial condition and
results of operations.
EMPLOYEES
On March 26, 1999, the Company had 66 full-time employees. None is
represented by any labor union. The Company believes its relations with its
employees are good. The Company also relies on several regional consulting
service companies to provide field landmen to support the Company on a
project-by-project basis. One of these companies, Brigham Land Management, is
owned by Vincent M. Brigham, who is the brother of Ben M. Brigham, the Company's
Chief Executive Officer, President and Chairman of the Board.
FACILITIES
The Company's principal executive offices are located in Austin, Texas,
where it leases approximately 34,330 square feet of office space at 6300 Bridge
Point Parkway, Building 2, Suite 500, Austin, Texas 78730. The Company also
leases a 4,100 square foot office at 450 Gears Road, Suite 240, Houston, Texas
77067.
TITLE TO PROPERTIES
The Company believes it has satisfactory title, in all material respects,
to substantially all of its producing properties in accordance with standards
generally accepted in the oil and gas industry. The Company's properties are
subject to royalty interests, standard liens incident to operating agreements,
liens for current taxes and other inchoate burdens which the Company believes do
not materially interfere with the use of or affect the value of such properties.
The Company's Credit Facility (as defined) is secured by a first lien against
substantially all of the Company's oil and natural gas properties and other
tangible assets, and the Company's Subordinated Notes (as defined) are secured
by a second lien against all collateral pledged by the Company as security under
its Credit Facility. See "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations."
GOVERNMENTAL REGULATION
The Company's oil and natural gas exploration, production and marketing
activities are subject to extensive laws, rules and regulations promulgated by
federal and state legislatures and agencies. Failure to comply with such laws,
rules and regulations can result in substantial penalties. The legislative and
regulatory burden on the oil and gas industry increases the Company's cost of
doing business and affects its profitability. Although the Company believes it
is in substantial compliance with all applicable laws and regulations, because
those laws and regulations are frequently amended, interpreted and
reinterpreted, the Company is unable to predict the future cost or impact of
complying with such laws and regulations.
The State of Texas and many other states require permits for drilling
operations, drilling bonds and reports concerning operations and impose other
requirements relating to the exploration and production of natural gas and oil.
These states also have statutes or regulations addressing conservation matters,
including provisions for the unitization or pooling of natural gas and oil
properties, the establishment of maximum rates of production from wells and the
regulation of spacing, plugging and abandonment of such wells.
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ENVIRONMENTAL MATTERS
The Company's operations and properties are, like the oil and gas industry
in general, subject to extensive and changing federal, state and local laws and
regulations relating to environmental protection, including the generation,
storage, handling, emission, transportation and discharge of materials into the
environment, and relating to safety and health. The recent trend in
environmental legislation and regulation generally is toward stricter standards,
and this trend will likely continue. These laws and regulations may require the
acquisition of a permit or other authorization before construction or drilling
commences and for certain other activities; limit or prohibit seismic
acquisition, construction, drilling and other activities on certain lands lying
within wilderness and other protected areas; and impose substantial liabilities
for pollution resulting from the Company's operations. The permits required for
various of the Company's operations are subject to revocation, modification and
renewal by issuing authorities. Governmental authorities have the power to
enforce compliance with their regulations, and violations are subject to fines
or injunction, or both. In the opinion of management, the Company is in
substantial compliance with current applicable environmental laws and
regulations, and the Company has no material commitments for capital
expenditures to comply with existing environmental requirements. Nevertheless,
changes in existing environmental laws and regulations or in interpretations
thereof could have a significant impact on the Company, as well as the oil and
gas industry in general. The Comprehensive Environmental Response, Compensation
and Liability Act ("CERCLA") and comparable state statutes impose strict and
arguably joint and several liability on owners and operators of certain sites
and on persons who disposed of or arranged for the disposal of "hazardous
substances" found at such sites. It is not uncommon for the neighboring land
owners and other third parties to file claims for personal injury and property
damage allegedly caused by the hazardous substances released into the
environment. The Resource Conservation and Recovery Act ("RCRA") and comparable
state statutes govern the disposal of "solid waste" and "hazardous waste" and
authorize imposition of substantial fines and penalties for noncompliance.
Although CERCLA currently excludes petroleum from its definition of "hazardous
substance," state laws affecting the Company's operations impose clean-up
liability relating to petroleum and petroleum related products. In addition,
although RCRA classifies certain oil field wastes as "non-hazardous," such
exploration and production wastes could be reclassified as hazardous wastes
thereby making such wastes subject to more stringent handling and disposal
requirements.
Federal regulations require certain owners or operators of facilities that
store or otherwise handle oil, such as the Company, to prepare and implement
spill prevention, control countermeasure and response plans relating to the
possible discharge of oil into surface waters. The Oil Pollution Act of 1990
("OPA") contains numerous requirements relating to the prevention of and
response to oil spills into waters of the United States. For onshore and
offshore facilities that may affect waters of the United States, the OPA
requires an operator to demonstrate financial responsibility. Regulations are
currently being developed under federal and state laws concerning oil pollution
prevention and other matters that may impose additional regulatory burdens on
the Company. In addition, the Clean Water Act and analogous state laws require
permits to be obtained to authorize discharge into surface waters or to
construct facilities in wetland areas. With respect to certain of its
operations, the Company is required to maintain such permits or meet general
permit requirements. The Environmental Protection Agency ("EPA") recently
adopted regulations concerning discharges of storm water runoff. This program
requires covered facilities to obtain individual permits, participate in a group
or seek coverage under an EPA general permit. The Company believes that it will
be able to obtain, or be included under, such permits, where necessary, and to
make minor modifications to existing facilities and operations that would not
have a material effect on the Company.
The Company has acquired leasehold interests in numerous properties that
for many years have produced natural gas and oil. Although the Company believes
that the previous owners of these interests have used operating and disposal
practices that were standard in the industry at the time, hydrocarbons or other
wastes may have been disposed of or released on or under the properties. In
addition, some of the Company's properties are operated by third parties over
whom the Company has no control. See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Other Matters" and
"-- Risk Factors -- Compliance with Environmental Regulations."
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ITEM 2. PROPERTIES
PRIMARY EXPLORATION PROVINCES
Brigham focuses its 3-D seismic exploration efforts in natural gas and oil
producing provinces where it believes 3-D technology may be effectively applied
to generate relatively large potential reserve volumes per well and per field,
high potential production rates and multiple producing objectives. Brigham's
exploration activities are concentrated primarily in three core provinces: the
Anadarko Basin of western Oklahoma and the Texas Panhandle; the onshore Gulf
Coast of south Texas and, to a lesser extent, the transition zone of Louisiana;
and West Texas. Brigham is concentrating substantially all of its current 3-D
seismic and drilling activities on its natural gas projects in its Anadarko
Basin and Gulf Coast provinces primarily due to the continuation of historically
low oil prices which has made its inventory of potential drilling locations in
its West Texas province less economically attractive.
Brigham has made significant investments in 3-D seismic and prospective
acreage in its Anadarko Basin and Gulf Coast provinces during the past three
years. Through these investments, the Company believes it has assembled an
inventory of potential drilling locations that will support a multi-year
drilling program, thereby providing attractive opportunities for long-term
growth. Based upon the interpreted portion of its 3-D seismic data as of
December 31, 1998, the Company estimates that it has identified approximately
700 potential undrilled locations within its three core exploration provinces.
From inception in 1990 through 1998, Brigham has achieved net drilling costs of
$0.82 per Mcfe added through its 3-D seismic exploration efforts. In addition,
over 500 of Brigham's estimated potential drilling locations are in its
currently active Anadarko Basin and Gulf Coast provinces where the Company has
achieved inception-to-date net drilling costs of $0.68 and $0.59 per Mcfe,
respectively. Furthermore, the Company estimates that approximately 800 square
miles of its 1,213 total square miles of 3-D seismic data acquired in 1998 had
either not been interpreted or only partially interpreted at December 31, 1998,
which should provide additional potential drilling locations.
As a result of the Company's substantial investments to identify potential
drilling locations and its currently limited capital resources, Brigham intends
to devote substantially all of its efforts and available capital resources in
1999 to the drilling and monetization of its highest grade prospects identified
or to be identified from its over 5,000 square mile inventory of 3-D seismic
data. The Company's current 1999 capital budget is estimated to be $17.5
million, which represents a significant reduction from 1998 expenditures and its
previously anticipated 1999 levels in an effort to match Brigham's current and
expected future capital resources. The Company's budgeted 1999 capital
expenditures consist of approximately $10 million to drill an estimated 20 to 25
gross wells, $3.5 million for seismic and land costs (primarily previous
commitments and obligations to acquire 3-D data and acreage), and $4 million for
capitalized general and administrative expenses and other fixed asset
expenditures. Brigham expects that its 1999 drilling expenditures will be
allocated approximately 50% to its Anadarko Basin province and 50% to its Gulf
Coast province, and such expenditures will be devoted to the drilling of the
highest grade prospects in the Company's inventory of identified potential
drilling locations. Additionally, Brigham's 1999 drilling program will be
concentrated within trends where the Company has experienced exploration success
to date. Management believes that the Company has an attractive opportunity to
profitably drill its highest grade 3-D delineated locations due to its
historical drilling costs and the currently low cost drilling environment.
Therefore, management's goal is to access additional capital to further monetize
its prospect inventory. As a result, the Company's actual capital expenditures
in 1999 may differ significantly from these estimates based upon capital
availability during the year. See "Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations -- Liquidity" and "-- Capital
Resources".
Although the Company is interpreting 3-D seismic data within the provinces
discussed below and has identified an estimated 700 potential drilling locations
yet to be drilled in those provinces, there can be no assurance that any of the
remaining seismic data will be interpreted or will generate additional drilling
locations or that any potential drilling locations will be drilled at all or
within the expected time frame. The final determination with respect to the
drilling of any well, including those currently budgeted, will depend on a
number of factors, including (i) the results of exploration efforts and the
review and analysis of the seismic data, (ii) the availability of sufficient
capital resources by the Company and other participants for drilling prospects,
(iii) economic and industry conditions at the time of drilling, including
prevailing and anticipated prices for oil and natural gas and the availability
of drilling rigs and crews, (iv) the financial resources and results of the
Company and (v) the availability of leases on reasonable terms
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and permitting for the potential drilling location. There can be no assurance
that the budgeted wells will, if drilled, encounter reservoirs of commercial
quantities of natural gas or oil.
Anadarko Basin
The Anadarko Basin is a prolific natural gas province that the Company
believes offers a combination of lower risk exploration and development
opportunities in shallower horizons and deeper, higher potential objectives that
have been relatively under explored. This province has produced in excess of 90
Tcfe to date from numerous, historically elusive stratigraphic targets, such as
the Red Fork, Upper Morrow and Springer channel sands, as well as from deeper,
higher potential structural objectives, such the Lower Morrow sandstones and the
Hunton and Arbuckle carbonates. In some cases, these objectives have produced in
excess of 30 Bcf of natural gas from a single well at rates of up to 30 MMcf of
natural gas per day. In addition, drilling economics in the Anadarko Basin are
enhanced by the multi-pay nature of many of the prospects in this province, with
secondary or tertiary targets serving as either incremental value or bailout
potential relative to the primary target zone.
Each of the stratigraphic and structural objectives in the Anadarko Basin
can provide excellent targets for 3-D seismic imaging. The Company has assembled
an extensive digital data base in this province, including geologic studies,
basin wide geologic tops, production data, well data, geographic data and over
8,400 miles of 2-D seismic data. Working with its team of in-house geologists
and supplemented by consulting geologists, the Company's explorationists
integrate this data with their extensive expertise and knowledge base to
generate 3-D projects in the Anadarko Basin.
Following its initial 3-D seismic acquisition in the province in 1991 (12.5
square miles), the Company acquired 51 square miles of 3-D seismic in the
Anadarko Basin in 1993. Over the last several years the Company has accelerated
its activity in the Anadarko Basin, acquiring 151 square miles of 3-D seismic in
1994, 195 square miles in 1995, 457 square miles in 1996, 675 square miles in
1997 and 583 square miles in 1998. The Company retained a 75% average working
interest in its 1997 and 1998 Anadarko Basin 3-D seismic projects which
consisted of an aggregate of 1,258 square miles of 3-D seismic data.
As of December 31, 1998, the Company had acquired 2,124 square miles (1.4
million acres) of 3-D seismic data in the Anadarko Basin, of which an estimated
300 square miles had either not been interpreted or only partially interpreted.
The Company does not currently intend to acquire additional 3-D seismic data in
this province in 1999. As of December 31, 1998, Brigham had completed 71 wells
in 95 attempts (75% success rate) in the Anadarko Basin and had found cumulative
net proved reserves of 48 Bcfe at an average net drilling cost of $0.68 per
Mcfe. In addition to its drilling activity in this province, the Company
acquired 21.5 Bcfe of net proved reserves in the Anadarko Basin in late 1997 at
a cost of $0.63 per Mcfe in an effort to capture additional prospects for future
potential drilling. In its Anadarko Basin drilling program in 1998, the Company
completed 27 wells in 40 attempts (68% success rate) with an average working
interest of 50%, resulting in the addition of 9.5 net Bcfe of proved reserves
(including revisions to prior years' estimates) at an average net drilling cost
of $1.93 per Mcfe. Brigham's Anadarko Basin net drilling costs per Mcfe in 1998
were negatively impacted by the unsuccessful drilling of several proved
undeveloped locations booked during 1997, particularly three high equity
interest direct offset locations to the Company's Christopher 84 #1 Lower Morrow
discovery in Hemphill County, Texas, and by several unsuccessful exploratory
wells with high equity interests that were drilled late in the year. Despite the
disappointing drilling costs realized in 1998, the Company has achieved average
net drilling costs of $0.68 per Mcfe in its Anadarko Basin province from 1994 to
1998. As of December 31, 1998, the Company had identified an estimated 430 3-D
delineated potential drilling locations in the Anadarko Basin, of which the
Company intends to drill 10 to 15 gross wells in 1999 with an estimated average
working interest of 40%.
As part of its strategic initiatives to improve its capital resources and
liquidity in 1999, Brigham is currently marketing three producing property
packages among its Anadarko Basin province reserve base. These three packages
consist of proved reserves totaling approximately 41 net Bcfe as of December 31,
1998. The Company may or may not divest all or a portion these reserves,
depending primarily upon the offers received during the marketing process.
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Brigham intends to focus its 1999 exploration activities in its Anadarko
Basin province in the following key project areas:
Arnett Project
Brigham's Arnett Project covers approximately 129,000 acres in Ellis
County, Oklahoma, and targets Morrow and Hunton producing horizons at depths of
10,000 to 14,000 feet. In 1997 and 1998, the Company acquired 127 square miles
of 3-D seismic in the first three of four planned phases of this project.
Following seismic interpretation and initial prospect delineation on this data,
Brigham began drilling in the Arnett Project in late 1998. While two of the
first three exploration wells in this project were unsuccessful, the Company was
completing a fourth well in mid- March 1999 in the primary objectives, the
Hunton and Morrow, and has logged additional pay behind pipe in a secondary pay
zone, the Tonkawa. Successful completion and production results from this well
could provide offset development drilling opportunities particularly for the
Morrow which is productive in the immediate area. In mid- March 1999, a fifth
well was drilling in this project, also targeting the Hunton and Morrow as
primary objectives. Following the sale of a portion of its interest in this
project in early 1999, Brigham retains a 70% effective working interest in its
Arnett Project. See "Item 1. Business -- Industry Alliances -- Duke Project
Financing".
Falcon Project
Brigham's Falcon Project covers approximately 43,500 acres in the
northeastern portion of the Texas Panhandle in Lipscomb County, Texas. This
project is located in an area which produces from a number of Pennsylvanian-aged
sands, with primary targets in the Upper and Lower Morrow and secondary targets
in the shallower Tonkawa and Cleveland sands. The Upper and Lower Morrow zones
produce from horizons in the area at depths ranging from 9,000 to 12,000 feet.
The Falcon Project is located within a trend where Brigham has considerable
exploration history having acquired over 280 miles of 3-D seismic and discovered
over 37 Bcfe of gross reserves in the Upper and Lower Morrow reservoirs. Based
on this historical success, the Company acquired an additional 68 square miles
of 3-D seismic data in its Falcon Project during the second half of 1998 and has
already delineated several Upper and Lower Morrow prospects in the early stages
of interpretation. Brigham spud the first exploration well in its Falcon Project
in March 1999 to test a potentially significant Lower Morrow sand structural
feature with associated upside potential in the shallower Tonkawa sands. Based
on predrill estimates, gross unrisked reserve potential for this structural
prospect is over 5 Bcfe. Following the sale of a portion of its interest in this
project in early 1999, Brigham retains a 70% effective working interest in its
Falcon Project. See "Item 1. Business -- Industry Alliances -- Duke Project
Financing".
Gold Project
The Gold Project is located in Dewey and Blaine Counties, Oklahoma, and
targets dual natural gas producing objectives in the Morrow sandstones and
Hunton carbonates at depths of 9,500 to 11,500 feet. The initial acquisition of
89 square miles of 3-D seismic data covering the project acreage was completed
in 1996 and drilling activity commenced in 1998 resulting in two Hunton and one
Morrow discovery. The Thomas #2 well (Brigham 34% working interest) discovered
2.4 gross Bcfe of proved reserves in the Hunton formation at a depth of 11,450
feet and was producing 2.5 MMcf of natural gas per day in mid-March 1999. The
Thomas #2 is producing from a location which is believed to be associated with a
potentially larger Hunton natural gas accumulation which could lead to several
development locations. The Willie Porter #1 well (Brigham 34% working interest)
found 2.3 gross Bcfe of proved reserves in the Hunton formation at 12,250 feet
and was producing at a rate of 570 Mcf of natural gas per day in mid- March
1999. In late 1998, the Sturgeon State #1 (Brigham 34% working interest) was
completed in a Morrow sand zone and was producing 70 Bbls of oil per day in
mid-March 1999 before stimulation of the well. The Company and its participants
have a number of additional Hunton and Morrow locations, mostly extensional and
developmental in nature, planned for drilling in the Gold Project in 1999.
Brigham has a 37.5% working interest in its Gold Project.
Huskie and Boilermaker Projects
Brigham's Huskie and Boilermaker Projects consist of 103 and 96 square
miles, respectively, of continuous 3-D seismic data covering approximately
127,000 acres in Blaine County, Oklahoma. These projects target stratigraphic
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sand channels in the Springer with additional stratigraphic sand objectives in
the Red Fork and Morrow in several identified prospects. Brigham initiated
acquisition of data in its Huskie Project in 1996 where it retained a 37.5%
working interest and, based upon the prospect density and reserve potential
interpreted from this initial data set, the Company subsequently acquired data
in its adjacent Boilermaker Project in 1998 where it retained a 100% working
interest. The Company assembled acreage over a number of potential drilling
locations in these project areas during 1998 and has at least one exploratory
well planned for each project in 1999. An exploratory well in the Huskie Project
will test a prospect with greater than 15 Bcfe of gross unrisked reserve
potential which is an extension to a prolific Springer channel that has produced
over 128 Bcfe of natural gas. Success from this initial exploratory well would
likely establish several development locations.
Wildcat and Panther Projects
The Company's Wildcat and Panther Projects consist of 50 and 99 square
miles, respectively, of continuous 3-D seismic data covering approximately
95,000 acres in the southern portion of the Texas Panhandle in Wheeler County,
Texas and Beckham County, Oklahoma. The primary exploration targets within these
projects are high potential, structural features at depths ranging from 7,500 to
21,000 feet. Brigham initiated acquisition of data in its Wildcat Project in
1997 where it retained a 37.5% working interest. Based upon the interpretation
of this initial data set, the Company subsequently acquired data in its adjacent
Panther Project in 1998 where it retained a 100% working interest. In its
Wildcat Project, the Company has a deep 21,000 foot exploratory well planned for
the second half of 1999 to drill an updip location to a Hunton well that has
produced over 14.5 Bcfe since 1981 and was still producing in mid-March 1999.
The Company believes successful completion of this exploratory test could prove
up an additional 27 Bcfe of remaining gross unrisked reserves in the attic of
this producing structure. Also in the second half of 1999, the Company plans to
drill a 7,500 foot test for 17 Bcfe of gross unrisked potential reserves in a
dual objective Brown Dolomite/Granite Wash structure.
Chitwood Project
Brigham's Chitwood Project consists of approximately 13 square miles of 3-D
seismic data located in the prolific Carter Knox anticline in Grady County,
Oklahoma. This project targets a mix of intermediate and deep prospects that
range from lower risk, development locations to higher risk, exploratory
objectives. Brigham initially entered this area with its 24 square mile West
Bradley Project acquired in 1994. In November 1997, the Company acquired an
interest in the producing Chitwood properties and undeveloped acreage which is
located adjacent to the West Bradley Project area. During 1998, as part of a
larger 142 square mile non-proprietary 3-D survey, Brigham and its project
participant acquired 13 square miles of 3-D seismic data over the entire
Chitwood Project, which led to the delineation of a number of prospects in the
Springer, Big Four, and Bromide that are developmental and extensional in
nature. In addition, the Company also imaged a large Arbuckle structure with in
excess of 100 Bcfe of gross unrisked reserve potential which has not been
optimally tested. The targeted objectives in the Chitwood Project range in depth
from 12,000 to 19,000 feet. In March 1999, the Company and its project
participant drilled the first well in the Chitwood Project based upon
interpretation of the recently acquired 3-D seismic data. The Chitwood
Boatwright Sand Unit #9 (Brigham working interest 50%) was completed in the
Springer formation at a depth of 11,970 feet and was testing 300 Bbls of oil and
500 Mcf gas per day in mid-March 1999. Brigham and its project participant have
delineated over 25 potential 3-D drilling locations among the four primary
objectives within the Chitwood Project. Brigham has retained a 50% working
interest in its Chitwood Project.
As part of its strategic initiatives to raise capital for its 1999
exploration program, the Company is marketing its 50% working interest in
acreage and producing wells in the Chitwood Project. To the extent that the
Company does not receive adequate offers for its interest in this project,
Brigham may retain its interest and engage in further drilling of its identified
locations in the Chitwood Project during 1999.
Gulf Coast
The onshore Gulf Coast region of Texas and South Louisiana is a high
potential, multi-pay province that lends itself to 3-D seismic exploration due
to its substantial structural and stratigraphic complexity. The Company has
assembled a digital data base including geographical, production, geophysical
and geological information that the
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Company evaluates on its CAEX workstations. Working with a team of in-house
geologists supplemented by consultants, the Company integrates this data with
their extensive expertise and knowledge base to generate 3-D projects in the
Gulf Coast. The Company has assembled projects in the Expanded Wilcox and
Expanded Vicksburg trends in South Texas, the Miocene and Upper, Middle, and
Lower Frio trends of the mid-to-southern regions of Texas, and the Lower Miocene
trend in the transition zone of South Louisiana, each of which are active 3-D
seismic exploration trends.
Brigham was attracted to the Gulf Coast province because of the opportunity
to apply the Company's established 3-D seismic exploration approach and its
staff's extensive Gulf Coast experience to a prolific, highly complex structural
province with potential to discover significant natural gas reserves and
production. The Company initiated its Gulf Coast effort in 1995 with the
acquisition of 39 square miles of seismic data in its Esperson Dome Project in
which the Company retained a small net profits interest that converts to a
variable back-in working interest of 12% to 20% upon project payout. Brigham's
exploration efforts in its Esperson Dome Project to date have yielded the
discovery of approximately 22 Bcfe of gross proved reserves from 11 wells,
mostly from objectives above 6,000 feet, with a number of prospects still
remaining to be drilled. Over the last three years the Company has accelerated
its activity in the Gulf Coast, acquiring 115 square miles of 3-D seismic in
1996, 404 square miles in 1997, and 590 square miles in 1998. The Company
retained a 77% average working interest in its Gulf Coast 3-D seismic projects
acquired from 1996 through 1998 which consisted of an aggregate of 1,109 square
miles of 3-D seismic data. Brigham anticipates that its increased project
assemblage and 3-D seismic acquisition activity in the Gulf Coast will result in
the allocation of a higher percentage of its drilling budget to this province in
1999, and will be a significant factor in the Company's future growth.
A portion of Brigham's 3-D seismic data acquisition in the Gulf Coast has
been accomplished by the Company's participation in certain non-proprietary, or
speculative, seismic programs. By converting certain of the Company's
proprietary seismic projects in core exploration areas to speculative data, the
Company was able to leverage these proprietary projects for access to
substantially larger non-proprietary speculative data for minimal or no
additional cost to the Company. The Company believes this 3-D seismic
acquisition strategy in the Gulf Coast, in certain circumstances, can accelerate
the addition of attractive potential drilling locations in targeted trends at
costs that are considerably less than those associated with proprietary 3-D
seismic programs, thereby enhancing expected project rates of return.
As of December 31, 1998, the Company had acquired 1,148 square miles
(734,720 acres) of 3-D seismic data in its Gulf Coast province, of which an
estimated 470 square miles had either not been interpreted or only partially
interpreted. The Company does not currently intend to acquire additional 3-D
seismic data in this province in 1999. As of December 31, 1998, Brigham had
completed 25 wells in 32 attempts (78% success rate) in the Gulf Coast and had
found cumulative proved reserves of 24 net Bcfe at an average net drilling cost
of $0.59 per Mcfe. In its Gulf Coast drilling program in 1998, the Company
completed 17 wells in 21 attempts with an average working interest of 59% adding
21 net Bcfe of proved reserves (including revisions to prior years' estimates)
at an average net drilling cost of $0.64 per Mcfe. As of December 31, 1998, the
Company had identified an estimated 120 3-D delineated potential drilling
locations in the Gulf Coast province, of which the Company intends to drill 10
gross wells in 1999 with an estimated average working interest of 55%.
Brigham intends to focus its 1999 exploration activities in its Gulf Coast
province in the following key project areas:
Diablo Project
Brigham's Diablo Project covers 57 square miles in Brooks County, Texas,
and targets shallow Frio and deep Vicksburg producing horizons. The Company has
entered into a venture with a major integrated oil company that controls
adjoining acreage to explore on the combined acreage for potential below 10,000
feet in the Vicksburg formation. Brigham has retained a 34% working interest in
this joint exploration project. However, in prospective zones above 10,000 feet,
primarily the Frio, Brigham has retained a 100% working interest in its original
4,000 acre lease block. The Company initially acquired 25 square miles of
proprietary 3-D seismic in this project in 1997, and
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acquired an additional 33 square miles in 1998 in its Diablo Project. The
Company and its participant control approximately 12,000 net acres of leasehold
in this project area.
In the fourth quarter of 1998, Brigham made a potentially significant Lower
Vicksburg discovery in its Diablo Project with the completion of the Brigham
Palmer State #1 well (Brigham 33% working interest). The Palmer State #1 was
successfully completed in three of five possible Lower Vicksburg pay zones at a
depths ranging from 9,600 to 12,800 feet and had initially tested at a rate of
2.8 MMcf of natural gas and 668 Bbls of condensate per day. This discovery well
appears to be located on the downdip flank of a structure which exceeds 800
acres in closure and contains potential reserves exceeding 50 Bcfe. A minimum of
five potential development locations have been identified on the crest of the
structure which are updip to the Palmer State #1 discovery well, the first of
which is expected to spud in the late second or early third quarter of 1999. In
addition, the Company has identified a large, downthrown, four-way closure in an
adjacent fault block which has produced over 86 Bcfe from the Frio formation,
but which has not been tested in the equivalent Vicksburg sands that produce in
the Company's Palmer State #1 well. Brigham plans to spud an exploratory well to
test this high potential faulted closure in mid-1999.
Southwest Danbury Project
Located in Brazoria County, Texas, Brigham's Southwest Danbury Project is
an approximate 29 square mile 3-D project targeting a series of pressured Lower
Frio sands at depths ranging from 12,000 to 13,000 feet. In the first half of
1998, the Brigham Nold Gas Unit #1 (Brigham working interest 46%) was drilled to
a depth of approximately 12,700 feet to test a Lower Frio amplitude, or bright
spot, and encountered 29 feet of net pay in the Rucks interval of the Lower Frio
sands. This well has produced at an average daily rate of 2.6 MMcf of natural
gas with 17 Bbls of condensate and 13 Bbls of water since August 1998. Based on
the results from this initial well, the Company spud the Brigham Renn Gas Unit
#1 (Brigham working interest 83.5%) in December 1998 to test another Lower Frio
3-D bright spot prospect with over 6 Bcfe gross unrisked reserve potential. This
well reached total depth and was in the process of completing in late March
1999. In addition, Brigham is evaluating several additional Lower Frio prospects
in its Southwest Danbury Project which could expose the Company to significant
upside potential.
Hawkins Ranch Project
Brigham's Hawkins Ranch Project is a 160 square mile 3-D seismic program in
the Miocene/Frio trend located in Matagorda County, Texas. In 1998, the Company
acquired approximately 85 square miles of new proprietary 3-D seismic that was
converted to speculative data and merged with 65 square miles of adjacent
speculative 3-D data already in inventory. The Hawkins Ranch Project targets
potential in the shallow, nonpressured Miocene and Frio sands as well as the
deeper, pressured Frio sands. In addition to the shallow Miocene potential, the
Company has identified a number of prospects targeting deeper Frio objectives in
its Hawkins Ranch Project. The first exploratory Frio well is planned to spud
during the second half of 1999. This well is a 14,000 foot pressured test of a
500 acre structure with associated gross unrisked reserve potential exceeding 33
Bcfe. Brigham retains a 60% working interest in this project, following the sale
of a 15% interest in the project to an industry participant for $1.5 million in
early 1999.
El Sauz Project
In May 1997, Brigham initiated its El Sauz Project with a seismic option
covering approximately 94,000 acres in Willacy and Kennedy Counties, Texas. In
1998, the Company acquired 200 square miles of 3-D seismic data over this
acreage and sold a 45% working interest in the project to two industry
participants which provided the Company with significant carry on the
pre-seismic land and seismic acquisition costs of the project. The El Sauz
Project is an underexplored area which is bordered on three sides by Miocene and
Frio fields which have in aggregate produced over 740 Bcf of natural gas and 94
MMBbls of oil. Primary targets in the El Sauz Project are expected to be in
Miocene and Frio sands at depths of 4,500 to 10,000 feet, with additional
potential as deep as 18,000 feet in the Lower Frio. Reserve targets range from 5
to 20 Bcf per well. Three prospects are planned for drilling in 1999, two of
which target the Frio at depths of 9,300 feet and 9,800 feet and one of which is
a Miocene test at 4,500 feet. Brigham retained a 55% working interest in its El
Sauz Project.
- 14 -
17
West Texas
The Company's limited drilling activity in the West Texas region in 1998
was focused in the Horseshoe Atoll, the Midland Basin and the Eastern Shelf of
the Permian Basin. Due to a combination of continuing low oil prices and less
than anticipated drilling results in its recent exploratory activity in this
province, the Company has ceased all 3-D seismic and drilling activities in its
West Texas projects and intends to focus substantially all of its exploration
efforts in 1999 on its predominately natural gas prospects in its Anadarko Basin
and Gulf Coast provinces. To the extent that oil prices improve in the future
from current levels, the Company would resume selective drilling of its
remaining undrilled locations in its West Texas province if such projects are
competitive with its Anadarko Basin and Gulf Coast projects based on estimated
risk adjusted, pre-drill economic return analysis.
As of December 31, 1998, the Company had acquired 1,689 square miles (1.1
million acres) in the West Texas region, the vast majority of which has been
interpreted. The Company does not currently intend to acquire additional 3-D
seismic data in this province for the foreseeable future. As of December 31,
1998, Brigham had completed 185 wells in 298 attempts (62% success rate) with an
average working interest of 23% in its West Texas province and had found
cumulative proved reserves of 20 net Bcfe at an average net drilling cost of
$1.39 per Mcfe. In its West Texas drilling program in 1998, the Company
completed 6 wells in 11 attempts with an average working interest of 45% adding
0.5 net Bcfe of proved reserves (including revisions to prior years' estimates)
at an average net drilling cost of $9.06 per Mcfe. As of December 31, 1998, the
Company had an estimated 140 3-D delineated potential drilling locations in the
West Texas region. The Company does not currently plan to drill any wells in its
West Texas province in 1999.
NATURAL GAS AND OIL RESERVES
The Company's estimated total net proved reserves of natural gas and oil as
of December 31, 1996, 1997 and 1998 and the present values attributable to these
reserves as of those dates were as follows:
AS OF DECEMBER 31,
------------------------------
1996(1) 1997 1998
-------- -------- --------
Estimated net proved reserves:
Natural gas (MMcf) ....................... 10,257 53,230 71,166
Oil (MBbls) .............................. 1,940 3,181 4,433
Natural gas equivalent (MMcfe) ........... 21,897 72,316 97,764
Proved developed reserves as a percentage
of proved reserves ....................... 67% 65% 57%
Present Value of Future Net Revenues
(in thousands) ........................... $ 44,506 $ 69,249 $ 81,741
Standardized Measure (in thousands) .......... $ 44,506 $ 64,274 $ 81,649
- -------------------------
(1) Prior to the Exchange consummated in February 1997, the Company was a
partnership and not subject to income taxes. Had the Company been a
taxable corporation at December 31, 1996, the Standardized Measure
would have been $32.4 million, reflecting a pro forma estimate for the
discounted value of future income taxes.
The reserve estimates reflected above were prepared by Cawley, Gillespie &
Associates, Inc. ("Cawley Gillespie"), the Company's petroleum consultants, and
are part of reports on the Company's oil and natural gas properties prepared by
Cawley Gillespie. The base sales prices for the Company's reserves were $3.71
per Mcf for natural gas and $25.37 per Bbl for oil as of December 31, 1996,
$2.27 per Mcf for natural gas and $15.50 per Bbl for oil as of December 31,
1997, and $2.12 per Mcf for natural gas and $9.50 per Bbl for oil as of December
31, 1998. These base prices were adjusted to reflect applicable transportation
and quality differentials on a well-by-well basis to arrive at realized sales
prices used to estimate the Company's reserves at these dates.
- 15 -
18
In accordance with applicable requirements of the SEC, estimates of the
Company's proved reserves and future net revenues are made using sales prices
estimated to be in effect as of the date of such reserve estimates and are held
constant throughout the life of the properties (except to the extent a contract
specifically provides for escalation). Estimated quantities of proved reserves
and future net revenues therefrom are affected by oil and natural gas prices,
which have fluctuated widely in recent years. There are numerous uncertainties
inherent in estimating oil and natural gas reserves and their estimated values,
including many factors beyond the control of the Company. The reserve data set
forth in this Form 10-K represents only estimates. Reservoir engineering is a
subjective process of estimating underground accumulations of oil and natural
gas that cannot be measured in an exact manner. The accuracy of any reserve
estimate is a function of the quality of available data and of engineering and
geologic interpretation and judgment. As a result, estimates of different
engineers, including those used by the Company, may vary. In addition, estimates
of reserves are subject to revision based upon actual production, results of
future development and exploration activities, prevailing oil and natural gas
prices, operating costs and other factors. The revisions may be material.
Accordingly, reserve estimates are often different from the quantities of oil
and natural gas that are ultimately recovered and are highly dependent upon the
accuracy of the assumptions upon which they are based. The Company's estimated
proved reserves have not been filed with or included in reports to any federal
agency. See "Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Risk Factors -- Uncertainty of Reserve Information
and Future Net Revenue Estimates."
Estimates with respect to proved reserves that may be developed and
produced in the future are often based upon volumetric calculations and upon
analogy to similar types of reserves rather than actual production history.
Estimates based on these methods are generally less reliable than those based on
actual production history. Subsequent evaluation of the same reserves based upon
production history will result in variations in the estimated reserves that may
be substantial.
DRILLING ACTIVITIES
The Company drilled, or participated in the drilling of, the following
number of wells during the periods indicated:
YEAR ENDED DECEMBER 31,
1996 1997 1998
-------------------- -------------------- --------------------
GROSS NET GROSS NET GROSS NET
--------- ---------- --------- ---------- --------- ----------
Exploratory Wells:
Natural gas............................................. 5 1.2 15 6.5 30 15.6
Oil..................................................... 22 5.2 21 7.9 7 2.5
Non-productive ......................................... 24 7.0 26 9.8 17 8.0
--------- ---------- --------- ---------- --------- ----------
Total................................................ 51 13.4 62 24.2 54 26.1
========= ========== ========= ========== ========= ==========
Development Wells:
Natural gas............................................. 10 1.3 4 1.6 10 6.6
Oil..................................................... 5 1.0 5 1.6 3 1.5
Non-productive ......................................... 1 0.2 2 0.9 5 3.4
--------- ---------- --------- ---------- --------- ----------
Total................................................ 16 2.5 11 4.1 18 11.5
========= ========== ========= ========== ========= ==========
The Company does not own any drilling rigs, and the majority of its
drilling activities have been conducted by industry participant operators or
independent contractors under standard drilling contracts. Consistent with its
business strategy, the Company has continued to retain operations of an
increasing number of the wells it drills. Brigham operated 57% of the gross and
76% of the net wells it participated in during 1998.
- 16 -
19
PRODUCTIVE WELLS AND ACREAGE
Productive Wells
The following table sets forth the Company's ownership interest as of
December 31, 1998 in productive natural gas and oil wells in the areas
indicated.
NATURAL GAS OIL TOTAL
--------------- ---------------- ---------------
PROVINCE GROSS NET GROSS NET GROSS NET
- -------- ----- ----- ----- ----- ----- ------
Anadarko Basin............................ 66 21.8 18 2.1 84 23.9
Gulf Coast................................ 15 5.7 8 3.0 23 8.7
West Texas ............................... 4 1.0 86 24.5 90 25.5
Other..................................... -- -- 5 0.8 5 0.8
----- ----- ----- ------ ----- ------
Total................................ 85 28.5 117 30.4 202 58.9
===== ===== ===== ====== ===== ======
Productive wells consist of producing wells and wells capable of
production, including wells waiting on pipeline connection. Wells that are
completed in more than one producing horizon are counted as one well. Of the
gross wells reported above, none had multiple completions.
Acreage
Undeveloped acreage includes leased acres on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of oil and natural gas, regardless of whether or not such acreage
contains proved reserves. A gross acre is an acre in which an interest is owned.
A net acre is deemed to exist when the sum of fractional ownership interests in
gross acres equals one. The number of net acres is the sum of the fractional
interests owned in gross acres expressed as whole numbers and fractions thereof.
The following table sets forth the approximate developed and undeveloped acreage
in which the Company held a leasehold, mineral or other interest at December 31,
1998:
DEVELOPED UNDEVELOPED TOTAL
----------------- ------------------- ------------------
PROVINCE GROSS NET GROSS NET GROSS NET
- -------- -------- ------- --------- -------- -------- --------
Anadarko Basin...................... 26,751 13,411 116,546 60,627 143,297 74,038
Gulf Coast.......................... 1,041 447 23,300 16,822 24,341 17,269
West Texas ......................... 6,570 1,898 18,740 7,919 25,310 9,817
Other............................... 520 148 48,189 18,105 48,709 18,253
-------- ------- --------- -------- -------- --------
Total............................ 34,882 15,904 206,775 103,473 241,657 119,377
======== ======= ========= ======== ======== ========
All the leases for the undeveloped acreage summarized in the preceding
table will expire at the end of their respective primary terms unless the
existing leases are renewed, production has been obtained from the acreage
subject to the lease prior to that date, or some other "savings clause" is
implicated. The following table sets forth the minimum remaining terms of leases
for the gross and net undeveloped acreage:
ACRES EXPIRING
-------------------------
GROSS NET
--------- ---------
Twelve Months Ending:
December 31, 1999.............................. 58,205 28,464
December 31, 2000.............................. 60,347 26,998
December 31, 2001.............................. 68,759 41,222
Thereafter..................................... 19,464 6,789
--------- ---------
Total..................................... 206,775 103,473
========= =========
- 17 -
20
In addition, the Company had lease options as of December 31, 1998 to
acquire an additional 173,670 gross (128,166 net) acres, substantially all of
which expire within eighteen months.
VOLUMES, PRICES AND PRODUCTION COSTS
The following table sets forth the production volumes, average prices
received and average production costs associated with the Company's sale of oil
and natural gas for the periods indicated.
YEAR ENDED DECEMBER 31,
-----------------------
1996 1997 1998
------ ------ ------
Production:
Natural gas (MMcf) ............................... 698 1,382 4,269
Oil (MBbls) ...................................... 227 291 396
Natural gas equivalent (MMcfe) ................... 2,060 3,126 6,644
Average sales price:
Natural gas (per Mcf) ............................ $ 2.30 $ 2.56 $ 2.04
Oil (per Bbl) .................................... 9.98 19.40 12.85
Average production expenses and taxes (per Mcfe) .... $ 0.53 $ 0.55 $ 0.46
COSTS INCURRED AND CAPITALIZED COSTS
The costs incurred in oil and natural gas acquisition, exploration and
development activities are as follows (in thousands):
YEAR ENDED DECEMBER 31,
-----------------------------
1996 1997 1998
-------- -------- --------
Cost incurred for the year:
Exploration..................................... $ 10,527 $ 29,516 $ 67,110
Property acquisition............................ 6,195 26,956 16,245
Development..................................... 1,328 2,953 10,427
Proceeds from participants...................... (4,111) (319) (10,502)
-------- -------- --------
$ 13,939 $ 59,106 $ 83,280
======== ======== ========
Costs incurred represent amounts incurred by the Company for exploration,
property acquisition and development activities. Periodically, the Company will
receive reimbursement of certain costs from participants in its projects
subsequent to project initiation in return for an interest in the project. These
payments are described as "Proceeds from participants" in the table above.
ITEM 3. LEGAL PROCEEDINGS
The Company is not a party to any material legal proceedings.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS
No matter was submitted to a vote of the Company's securityholders during
the fourth quarter of 1998.
- 18 -
21
EXECUTIVE OFFICERS OF THE REGISTRANT
Pursuant to Instruction 3 to Item 401(b) of the Regulation S-K and General
Instruction G(3) to Form 10-K, the following information is included in Part I
of this report.
The following table sets forth certain information concerning the executive
officers of the Company as of March 31, 1999:
NAME AGE POSITION
---- --- --------
Ben M. Brigham 39 Chief Executive Officer and President
Jon L. Glass 43 Vice President--Exploration
Craig M. Fleming 41 Chief Financial Officer
David T. Brigham 38 Vice President--Land and Administration, Corporate Secretary
A. Lance Langford 36 Vice President--Operations
Karen E. Lynch 37 Vice President and General Counsel
Set forth below is a description of the backgrounds of the executive
officers of the Company.
Ben M. "Bud" Brigham has served as Chief Executive Officer, President and
Chairman of the Board of the Company since founding the Company in 1990. From
1984 to 1990, Mr. Brigham served as an exploration geophysicist with Rosewood
Resources, an independent oil and gas exploration and production company. Mr.
Brigham began his career in Houston as a seismic data processing geophysicist
for Western Geophysical, a provider of 3-D seismic services, after earning his
B.S. in Geophysics from the University of Texas. Mr. Brigham is the husband of
Anne L. Brigham, Director, and the brother of David T. Brigham, Vice
President--Land and Administration and Corporate Secretary.
Jon L. Glass joined the Company in 1992 and has served as Vice President --
Exploration since 1994 and a Director of the Company since 1995. From 1984 to
1992, Mr. Glass served in various capacities with Santa Fe Minerals, an oil and
gas exploration company, in a variety of staff and managerial positions mainly
focused on Santa Fe Minerals' exploration activities in the midcontinent and
Gulf of Mexico (onshore and offshore). During this time Mr. Glass also assisted
in the development of exploration and acquisition opportunities for Santa Fe
Minerals in Canada and South America. Mr. Glass' early geological experience
includes three years with Mid-America Pipeline Company and two years with Texaco
USA, serving mainly as a midcontinent exploration geologist. Mr. Glass holds a
B.S. and an M.S. in Geology from Oklahoma State University and an M.B.A. from
the University of Tulsa.
Craig M. Fleming has served as the Chief Financial Officer of the Company
since 1993. From 1990 to 1993, Mr. Fleming served as Controller of Odyssey
Petroleum Co., Ltd., an independent energy company. From 1988 to 1990, Mr.
Fleming served as Controller and Treasurer for Harken Exploration Company, an
independent energy company. Mr. Fleming began his career with Arthur Anderson &
Co. in the Oil and Gas Audit Division and is a Certified Public Accountant. Mr.
Fleming holds a B.B.A. in Accounting from Texas A&M University.
David T. Brigham joined the Company in 1992 and has served as Vice
President -- Land and Administration and Corporate Secretary of the Company
since February 1998. Mr. Brigham served as Vice President -- Legal of the
Company from 1994 until February 1998. From 1987 to 1992, Mr. Brigham was an oil
and gas attorney with Worsham, Forsythe, Sampels & Wooldridge. Before attending
law school, Mr. Brigham was a landman for Wagner & Brown Oil and Gas Producers,
an independent oil and gas exploration and production company. Mr. Brigham holds
a B.B.A. in Petroleum Land Management from the University of Texas and a J.D.
from Texas Tech School of Law. Mr. Brigham is the brother of Ben M. Brigham,
Chief Executive Officer, President and Chairman of the Board.
A. Lance Langford joined the Company as Manager of Operations in 1995 and
has served as Vice President -- Operations since January 1997. From 1987 to
1995, Mr. Langford served in various engineering capacities with Meridian Oil
Inc., handling a variety of reservoir, production and drilling responsibilities.
Mr. Langford holds a B.S. in Petroleum Engineering from Texas Tech University.
- 19 -
22
Karen E. Lynch joined the Company in October 1997 as General Counsel and
has served as Vice President -- Legal and General Counsel of the Company since
February 1998. Prior to joining the Company, Ms. Lynch was a shareholder in the
Dallas-based law firm of Thompson & Knight, P.C., where she practiced in the
energy area since joining the firm in 1987. Ms. Lynch holds a B.B.A. in
Petroleum Land Management from the University of Texas and a J.D. from the
University of Oklahoma.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The Company's Common Stock (the "Common Stock") has been publicly traded on
The Nasdaq Stock Market(sm) under the symbol "BEXP" since the Company's initial
public offering effective May 8, 1997. The following table summarizes the high
and low last reported sales prices on Nasdaq for each quarterly period since the
Company's initial public offering:
COMMON STOCK
-----------------
HIGH LOW
------- -------
1997:
Second Quarter (from May 9, 1997)............................. $ 8.75 $ 7.00
Third Quarter................................................. $ 14.31 $ 8.25
Fourth Quarter................................................ $ 17.13 $ 12.00
1998:
First Quarter................................................. $ 14.00 $ 10.50
Second Quarter................................................ $ 15.50 $ 8.75
Third Quarter................................................. $ 10.25 $ 5.13
Fourth Quarter................................................ $ 9.50 $ 4.75
The closing market price of the Company's Common Stock on March 26, 1999
was $3.50 per share. As of March 26, 1999, the Company estimates that there were
more than 80 record and 1,100 beneficial owners of the Company's Common Stock.
No dividends have been declared or paid on the Company's Common Stock to
date. The Company intends to retain all future earnings for the development of
its business. In addition, the Credit Facility (as defined) and the Indenture
(as defined) restrict the Company's ability to pay dividends on the Company's
Common Stock.
- 20 -
23
ITEM 6. SELECTED FINANCIAL DATA
The following selected consolidated financial data should be read in
conjunction with "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations" and the Company's consolidated financial
statements and related notes included in "Item 8. Financial Statements and
Supplementary Data."
YEAR ENDED DECEMBER 31,
----------------------------------------------------
STATEMENT OF OPERATIONS DATA: 1994 1995 1996 1997 1998
-------- ------- -------- -------- ---------
Revenues:
Natural gas and oil sales....................... $ 2,565 $ 3,578 $ 6,141 $ 9,184 $ 13,799
Workstation revenue............................. 815 635 627 637 390
-------- ------- -------- -------- ---------
Total revenues.............................. 3,380 4,213 6,768 9,821 14,189
Costs and expenses:
Lease operating................................. 491 761 726 1,151 2,172
Production taxes................................ 126 165 362 549 850
General and administrative...................... 1,785 1,897 2,199 3,570 4,672
Depletion of oil and natural gas properties.... 1,104 1,626 2,323 2,743 8,410
Capitalized ceiling impairment................. -- -- -- -- 24,847
Depreciation and amortization .................. 561 533 487 694 785
-------- ------- -------- -------- ---------
Total costs and expenses.................... 4,067 4,982 6,097 8,707 41,736
-------- ------- -------- -------- ---------
Operating income (loss)......................... (687) (769) 671 1,114 (27,547)
Other income (expense):
Interest income................................. 56 128 52 145 136
Interest expense................................ (668) (936) (1,173) (1,190) (7,120)
-------- ------- -------- -------- ---------
Total other income (expense)................ (612) (808) (1,121) (1,045) (6,984)
Net income (loss) before income taxes........... (1,299) (1,577) (450) 69 (34,531)
Income tax expense, net......................... -- -- -- (1,186)(1) 1,186
-------- ------- -------- -------- ---------
Net loss.................................... $ (1,299) $(1,577) $ (450) $ (1,117)(1) $ (33,345)
======== ======= ======== ======== =========
Net loss per share.............................. $ (0.15) $ (0.18) $ (0.05) $ (0.10) $ (2.64)
======== ======= ======== ======== =========
Weighted average common shares outstanding...... 8,929 8,929 8,929 11,081 12,626
STATEMENT OF CASH FLOWS DATA:
Net cash provided by operating activities....... $ 626 $ 1,383 $ 3,710 $ 9,806 $ 13,622
Net cash used in investing activities........... (5,463) (8,005) (11,796) (57,300) (85,075)
Net cash provided by financing activities....... 4,634 7,724 7,731 47,748 72,321
OTHER FINANCIAL DATA:
Capital expenditures............................ $ 5,445 $ 7,935 $ 13,612 $ 57,170 $ 84,055
AS OF DECEMBER 31,
---------------------------------------------------
1994 1995 1996 1997 1998
------- -------- -------- -------- --------
BALANCE SHEET DATA:
Cash and cash equivalents .............. $ 700 $ 1,802 $ 1,447 $ 1,701 $ 2,569
Oil and natural gas properties, net .... 11,970 18,538 28,005 84,294 134,317
Total assets ........................... 15,781 22,916 33,614 92,519 150,516
Total debt ............................. 7,950 16,000 24,000 32,000 94,786
Total equity ........................... 5,271 3,694 3,244 43,313 24,681
(1) Includes a net $1.2 million ($0.10 per share) non-cash deferred income
tax charge related to the Company's conversion from a partnership to a
corporation in 1997.
- 21 -
24
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
OVERVIEW
The Company is an independent exploration and production company that
applies 3-D seismic imaging and other advanced technologies to systematically
explore and develop onshore oil and natural gas provinces in the United States.
From inception in 1990 through December 31, 1998, Brigham acquired 5,236 square
miles of 3-D seismic data, identified an estimated 1,140 potential drilling
locations and drilled 442 wells delineated by 3-D seismic analysis. Through its
3-D seismic-based drilling efforts, the Company had discovered an aggregate of
92 Bcfe of net proved reserves as of December 31, 1998. The Company believes
this performance demonstrates a systematic methodology for finding oil and
natural gas in onshore domestic oil and natural gas provinces.
Combining its geologic and geophysical expertise with a sophisticated land
effort, the Company manages the majority of its projects from conception through
3-D acquisition, processing and interpretation and leasing. In addition, the
Company manages the negotiation and drafting of most of its geophysical
exploration agreements, resulting in reduced contract risk and more consistent
deal terms. Because it generates most of its projects, the Company can control
the size of the working interest that it retains as well as the selection of the
operator and the non-operating participants. Consistent with its business
strategy, Brigham has increased the working interest it retained in its
projects, based on capital availability and perceived risk. The Company's
average working interest in its 3-D seismic projects acquired during 1996, 1997
and 1998 was 37%, 67% and 80%, respectively, while its average working interest
in its wells drilled during this period was 24%, 39% and 52%, respectively.
Beginning in 1995, the Company has managed operations through the drilling and
production phases on an increasing portion of its 3-D seismic projects. Brigham
operated 57% of its gross wells and 76% of its net wells drilled in 1998 as
compared with 10% of its gross wells and 16% of its net wells drilled in 1996.
Expenditures made in oil and natural gas exploration vary from project to
project depending primarily on the costs related to land, seismic acquisition,
drilling costs and the working interest retained by the Company. Historically,
the Company's participants have typically borne a disproportionate share of the
costs of optioning available acreage and acquiring, processing and interpreting
the 3-D seismic data, and the Company and its participants each typically
incurred leasing, drilling and completion costs in proportion to their ownership
interests. In recent years, Brigham has retained majority working interests in
its new 3-D seismic projects, and has thereby reduced the financial leverage it
has historically received on the costs of optioning available acreage and
acquiring, processing and interpreting the 3-D seismic data on its projects.
From inception through 1996, the Company acquired 2,761 gross (781 net)
square miles of 3-D seismic data. Initially, the Company focused its efforts in
West Texas. In 1995, the Company began to devote substantial attention to the
Anadarko Basin, and since 1996 the Company has devoted the majority of its
resources to the Anadarko Basin and Gulf Coast. With this shift in regional
focus, the majority of the Company's production volumes has shifted from oil to
natural gas. To finance these project generation and drilling activities, the
Company supplemented cash flow from operations with private placements of debt
and equity, commercial bank credit facilities and placements of working
interests in projects with industry participants. As the Company's cash flows
from operations and other sources of capital have increased during this period,
it retained larger average working interests in its projects.
In 1997 and 1998, the Company acquired 2,475 gross (1,810 net) square miles
of 3-D seismic and continued to focus the majority of its 3-D exploration
efforts in the Anadarko Basin and the Gulf Coast. During the past two years, the
Company acquired 1,258 square miles (51%) of 3-D seismic in the Anadarko Basin,
making this basin the most active 3-D seismic acquisition province for the
Company. Brigham also significantly increased its Gulf Coast activity, acquiring
994 square miles (40%) of 3-D seismic in this period. During 1997 and 1998, the
Company drilled 145 gross (65.9 net) wells based on its 3-D seismic data
analysis. In addition to its drilling activities, the Company acquired 21.3 net
Bcfe of proved reserves and an interest in undeveloped acreage (the "Chitwood
Acquisition") at the northern end of the Carter Knox anticline in Grady County,
Oklahoma for $13.4 million in November 1997. As a result of these activities,
the Company's net natural gas and oil production increased from 2.1 Bcfe in 1996
to 6.6 Bcfe
- 22 -
25
in 1998. The Company's net production volumes consisted of 79% natural gas on an
equivalent basis during the fourth quarter 1998 as compared with 36% during the
fourth quarter 1996. The Company supplemented cash flow from operations in 1997
and 1998 with borrowings under commercial bank credit facilities, $24 million
raised in its initial public offering of common stock in May 1997, $47.5 million
raised through the placement of debt and equity securities in August 1998 and
the placement of working interests in projects to industry participants to
finance its project generation, property acquisition and drilling activities.
The Company uses the full-cost method of accounting for its natural gas and
oil properties. Under this method, all acquisition, exploration and development
costs, including certain internal costs that are directly attributable to the
Company's acquisition, exploration and development activities, are capitalized
in the amortizable base of the "full-cost pool" as incurred. Upon the
interpretation by the Company of the 3-D seismic associated with unproved
properties, the geological and geophysical costs of acreage that is not
specifically identified as prospective are transferred to the amortizable base
of the full-cost pool. Geological and geophysical costs associated with
prospective acreage, as well as leasehold costs, are transferred to the
amortizable base of the full-cost pool when the prospects are drilled. The
Company records depletion of its full-cost pool using the unit of production
method.
To the extent that the costs capitalized in the full-cost pool (net of
depreciation, depletion and amortization and related deferred taxes) exceed the
present value (using a 10% discount rate and based on period-end natural gas and
oil prices) of estimated future net after-tax cash flows from proved natural gas
and oil reserves plus the capitalized cost of unproved properties, such costs
are charged to operations as a writedown of the carrying value of natural gas
and oil properties, or a "capitalized ceiling impairment" charge. The risk that
the Company will be required to write down the carrying value of its oil and gas
properties increases when oil and gas prices are depressed, even if such prices
are temporary. In addition, capitalized ceiling impairment charges may occur if
the Company experiences poor drilling results or has substantial downward
revisions in its estimated proved reserves. A capitalized ceiling impairment is
a charge to earnings that does not impact cash flows, but does impact operating
income and stockholders' equity. Once incurred, a capitalized ceiling impairment
charge to natural gas and oil properties cannot be reversed at a later date.
Primarily as a result of the significant declines in both oil and natural gas
prices at December 31, 1998 and disappointing drilling results on several of the
Company's high working interest wells in 1998, the Company recorded a
capitalized ceiling impairment charge at December 31, 1998 of $24.8 million (see
Note 2 of Notes to the December 31, 1998 Consolidated Financial Statements). No
assurance can be given that the Company will not experience a capitalized
ceiling impairment charge in future periods. See "-- Risk Factors -- Dependence
on Exploratory Drilling Activities"; "-- Risk Factors -- Volatility of Natural
Gas and Oil Prices"; and " -- Risk Factors -- Uncertainty of Reserve Information
and Future Net Revenue Estimates."
In connection with the Exchange in 1997, the Company issued options to
purchase 644,097 shares of Common Stock to certain of its officers and
employees. The Company recorded an unearned stock compensation balance of $2.5
million in the first quarter 1997, of which approximately one-half will be added
to the amortizable base of the full-cost pool over the vesting period of the
options and the balance will be recorded as a noncash compensation expense over
the vesting period of the options. As a result, the Company expects to incur
unearned stock compensation amortization expenses of approximately $189,000 in
1999, $115,800 in 2000 and an aggregate of $111,000 in the three years
thereafter.
The Company's predecessor was classified as a partnership for federal
income tax purposes. Therefore, no income taxes were paid or provided for by the
Company prior to the Exchange. The Company is a taxable entity. In connection
with the Exchange on February 27, 1997, the Company incurred a $5 million charge
to record a deferred income tax liability to recognize the differences between
the financial statement basis and tax basis of the Company's predecessor
partnership's natural gas and oil properties at the Exchange date, given the
provisions of enacted tax laws. During the fourth quarter 1997, the Company
elected to record a step-up in the basis of its assets for tax purposes as a
result of the Exchange. Due to this election, the Company recorded a $3.8
million non-cash deferred income tax benefit during the fourth quarter 1997,
which resulted in a net $1.2 million ($0.10 per dividend share) non-cash
deferred income tax charge for the year ended December 31, 1997.
- 23 -
26
RESULTS OF OPERATIONS
The following table sets forth certain operating data for the periods
presented.
YEAR ENDED DECEMBER 31,
----------------------------
1996 1997 1998
------- ------ -------
Production:
Natural gas (MMcf) ............................. 698 1,382 4,269
Oil (MBbls) .................................... 227 291 396
Natural gas equivalent (MMcfe) ................. 2,060 3,126 6,644
% Natural gas .................................. 34% 44% 64%
Average sales prices per unit (1):
Natural gas (per Mcf) .......................... $ 2.30 $ 2.56 $ 2.04
Oil (per Bbl) .................................. 19.98 19.40 12.85
Natural gas equivalent (per Mcfe) .............. 2.98 2.94 2.08
Costs and expenses per Mcfe:
Lease operating ................................ $ 0.35 $ 0.37 $ 0.33
Production taxes ............................... 0.18 0.18 0.13
General and administrative ..................... 1.07 1.14 0.70
Depletion of natural gas and oil properties .... 1.13 0.88 1.27
- ---------------
(1) Reflects the effects of the Company's hedging activities. See "Item 7.
Management's Discussion and Analysis of Financial Condition and Results
of Operations -- Other Matters -- Hedging Activities."
Year Ended December 31, 1998 Compared to Year Ended December 31, 1997
Natural gas and oil sales. Natural gas and oil sales increased 50% from
$9.2 million in 1997 to $13.8 million in 1998. Production volume increases
accounted for $9.4 million (204%) of this increase and were offset by $4.8
million (104%) from a decrease in the average sales price received for natural
gas and oil sales. Production volumes for natural gas increased 209% from 1,382
MMcf in 1997 to 4,269 MMcf in 1998. The average price received for natural gas
decreased 20% from $2.56 per Mcf in 1997 to $2.04 per Mcf in 1998. Production
volumes for oil increased 36% from 291 MBbls in 1997 to 396 MBbls in 1998. The
average price received for oil decreased 34% from $19.40 per Bbl in 1997 to
$12.85 per Bbl in 1998. Natural gas and oil sales in 1998 were increased by
production from wells completed and flowing to sales since December 31, 1997,
offset partially by the natural decline of existing production, and from certain
wells acquired in the Chitwood Acquisition which were included in the Company's
results of operations effective September 1, 1997. As a result of hedging
activities, natural gas revenues increased by $555,240 ($0.13 per Mcf) in 1998,
compared to a decrease in oil revenues of $6,191 ($0.02 per Bbl) in 1997. See
"-- Other Matters -- Hedging Activities."
Workstation revenue. Workstation revenue decreased 39% from $637,000 in
1997 to $390,000 in 1998. Workstation revenue is recognized by the Company as
industry participants in the Company's seismic programs are charged an hourly
rate for the work performed by the Company on its 3-D seismic interpretation
workstations. This decrease is primarily attributable to the Company's increased
working interests in its recently acquired 3-D seismic data, which reduces the
amount of workstation interpretation costs that the Company can bill to its
participants. The Company expects workstation revenue to continue to decline in
1999 due to the Company's increased working interests in the square miles of 3-D
seismic it acquired in 1997 and 1998.
Lease operating expenses. Lease operating expenses increased 89% from $1.2
million ($0.37 per Mcfe) in 1997 to $2.2 million ($0.33 per Mcfe) in 1998. This
increase was primarily due to an increase in the number of producing wells
during 1998 from those in 1997. The decrease in the per unit amount was
primarily due to an increase in natural gas production as a percentage of total
equivalent production (44% in 1997 and 64% in 1998) since a typical natural gas
well produces with lower average lease operating costs per unit of production
than a typical oil well.
- 24 -
27
Production taxes. Production taxes increased 55% from $549,000 ($0.18 per
Mcfe) in 1997 to $850,000 ($0.13 per Mcfe) in 1998 as a direct result of
increased production volumes. The effective average production tax rate
increased from 6% of natural gas and oil sales revenues in 1997 to 6.2% in 1998
due to the increase in natural gas production as a percentage of total
equivalent production as natural gas is typically burdened with higher
production tax rates than oil. The decrease in the per unit amount was primarily
attributable to the decline in natural gas and oil sales prices in 1998 as
compared with 1997.
General and administrative expenses. General and administrative expenses
increased 31% from $3.6 million ($1.14 per Mcfe) in 1997 to $4.7 million ($0.70
per Mcfe) in 1998. This increase was primarily attributable to the hiring of
additional personnel and related expenses necessary to manage the Company's
growing operations. The decrease in the per unit rate was a result of a greater
increase in natural gas and oil production volumes than general and
administrative expenses from 1997 to 1998 due to the aforementioned factors. The
Company has initiated an overhead reduction plan during 1999, consisting
primarily of a Company-wide salary reduction beginning in the second quarter of
1999 and the elimination or reduction of various other discretionary
administrative expenditures. The Company plans to continue to evaluate its
overhead cost structure during the course of 1999 and may take further steps to
reduce its administrative expenses depending upon the outcome of its various
strategic initiatives underway to improve its capital resources and liquidity.
Depletion of natural gas and oil properties. Depletion of natural gas and
oil properties increased 207% from $2.7 million ($0.88 per Mcfe) in 1997 to $8.4
million ($1.27 per Mcfe) in 1998. Of this increase, $4.5 million was
attributable to the increase in production volumes during the period and $1.2
million was due to the increase in the depletion rate per unit of production.
The increase in depletion rate per unit of production was primarily the result
of the addition of natural gas and oil reserves at higher average capital costs
due to a reduction in drilling performance and downward revisions to previous
reserve estimates.
Interest expense. Interest expense increased from $1.2 million in 1997 to
$7.1 million in 1998 due to the Company's higher average outstanding debt
balance in 1998 combined with a higher average effective interest rate. The
Company's weighted average outstanding debt balance increased 450% from $12
million in 1997 to $66 million in 1998. This increase in debt was incurred
primarily to fund the Company's increased capital expenditures and working
capital needs, net of operating cash flow, during 1998. The effective annual
interest rate on the Company's outstanding indebtedness increased from 9.4% in
1997 to 10.6% in 1998, primarily due to the Company's issuance of $40 million of
Senior Subordinated Secured Notes due 2003 (the "Subordinated Notes") in August
1998, which bore interest at an annual rate of 12% from the date of issuance. In
addition, interest expense in 1998 included (i) approximately $1 million of
non-cash charges related to the amortization of deferred loan fees and the
amortization of discount on the Subordinated Notes, and (ii) $507,000 of
interest expenses related to the Subordinated Notes that was paid through the
issuance of additional Subordinated Notes in lieu of cash in February 1999.
Pursuant to the recently amended terms of the Credit Facility and the
Subordinated Notes, the Company expects to pay its interest obligations related
to the Subordinated Notes in 1999 through the issuance of additional
Subordinated Notes in lieu of cash in an effort to preserve cash flow to fund
capital expenditures and working capital. Borrowings under the Company's
commercial bank credit facility had an effective annual interest rate of 7.2% at
December 31, 1998. See "-- Liquidity" and "-- Capital Resources."
Year Ended December 31, 1997 Compared to Year Ended December 31, 1996
Natural gas and oil sales. Natural gas and oil sales increased 50% from
$6.1 million in 1996 to $9.2 million in 1997. Production volume increases
accounted for $3.2 million (104%) of this increase and were offset by $134,000
(4%) from a decrease in the average sales price received for natural gas and oil
sales. Production volumes for natural gas increased 98% from 698,036 Mcf in 1996
to 1,381,996 Mcf in 1997. The average price received for natural gas increased
11% from $2.30 per Mcf in 1996 to $2.56 per Mcf in 1997. Production volumes for
oil increased 28% from 226,925 Bbls in 1996 to 290,624 Bbls in 1997. The average
price received for oil decreased 3% from $19.98 per Bbl in 1996 to $19.40 per
Bbl in 1997. Natural gas and oil sales were increased by production from 46
wells completed in 1997, which was partially offset by the natural decline of
existing production. Hedging activities in 1997 reduced the amount by which oil
revenues increased by $6,191, compared to a decrease in oil revenues of $301,280
as a result of hedging activities in 1996.
- 25 -
28
Workstation revenue. Workstation revenue increased 2% from $627,000 in 1996
to $637,000 in 1997. Workstation revenue is recognized by the Company as
industry participants in the Company's seismic programs are charged an hourly
rate for the work performed by the Company on its 3-D seismic interpretation
workstations.
Lease operating expenses. Lease operating expenses increased 59% from
$726,000 ($0.35 per Mcfe) in 1996 to $1.2 million ($0.37 per Mcfe) in 1997. The
increase was primarily due to an increase in producing wells during the year.
Production taxes. Production taxes increased 52% from $362,000 ($0.18 per
Mcfe) in 1996 to $549,000 ($0.18 per Mcfe) in 1997 as a direct result of
increased production volumes. The effective average production tax rate remained
unchanged at 6% of natural gas and oil sales revenues for each period.
General and administrative expenses. General and administrative expenses
increased 62% from $2.2 million ($1.07 per Mcfe) in 1996 to $3.6 million ($1.14
per Mcfe) in 1997. Approximately $300,000 of the increase in 1997 resulted from
nonrecurring expenses related to the Company's relocation of its corporate
headquarters from Dallas, Texas to Austin, Texas, and the balance was primarily
attributable to the hiring of additional personnel and related expenses
necessary to manage the Company's growing operations. The increase in the per
unit rate was a result of a greater increase in aggregate general and
administrative expenses than natural gas and oil production volumes from 1996 to
1997 due to the aforementioned factors.
Depletion of natural gas and oil properties. Depletion of natural gas and
oil properties increased 18% from $2.3 million ($1.13 per Mcfe) in 1996 to $2.7
million ($0.88 per Mcfe) in 1997 as a result of higher production volumes.
The per unit amount decreased due to the addition of proved reserves during
1997.
Interest expense. Interest expense was essentially unchanged from 1996 to
1997 as the Company's lower average outstanding debt balance in 1997 was offset
by a higher effective average interest rate. The weighted average outstanding
debt balance decreased 39% from $19.7 million in 1996 to $12 million in 1997.
The effective interest rate increased 83% from 5.7% in 1996 to 10.5% in 1997.
The decrease in the weighted average outstanding debt balance and increase in
the effective average interest rate resulted primarily from the conversion to
equity of privately placed 5% notes in February 1997, the retirement of $13.3
million of borrowings under its previous credit facility in connection with the
Company's May 1997 initial public offering, and $32 million of borrowings
incurred under its previous credit facility subsequent to the Company's initial
public offering to fund the Company's increased exploration activity and its
$13.5 million acquisition of properties from Mobil adjacent to its West Bradley
3-D Project area. The Company's previous credit facility had an effective
interest rate of 8.8% at December 31, 1997.
LIQUIDITY
Despite the Company's success in building its inventory of 3-D seismic data
and potential drilling locations, a number of key factors have recently
contributed to significantly limit the Company's capital resources available to
fund its continued long-term growth-oriented exploration strategy. Management
believes these principal factors include: (i) lower commodity sales prices,
which reduced revenues and cash flow from the Company's production volumes, (ii)
reduced access to public, private and industry sources of capital on
cost-effective terms due to the continuing low commodity price environment and
outlook, (iii) less than anticipated success in placing working interests with
industry or financial participants in certain of its high equity interest
projects, resulting in lower levels of project cost recoupment than budgeted,
(iv) high levels of expenditures for 3-D seismic and land activities that do not
generate proved reserves and cash flow until the drilling stage of the project
cycle, (v) the utilization of high levels of debt to fund its accelerating
exploration expenditures, and (vi) disappointing drilling results during 1998 on
a number of high equity interest exploratory and development wells, several of
which were completed and subsequently plugged and abandoned or otherwise
performed below expectations.
As a result of these limiting factors and an expectation for continuing
difficult industry and capital markets conditions, Brigham has substantially
reduced its planned capital budget for 1999 and has undertaken a number of
strategic initiatives in an effort to improve and preserve its capital liquidity
in the current environment. While the Company remains focused on its long-term
growth objectives and the continuation of its established business model
- 26 -
29
for 3-D seismic-based exploration, Brigham has adapted its business strategy in
the near-term in an effort to maximize value for its shareholders on a long-term
basis through the implementation of the following principal strategic
initiatives: (i) focusing all of the Company's planned exploration efforts in
1999 toward the drilling of its highest- grade 3-D prospects identified in its
Anadarko Basin and Gulf Coast projects, concentrated primarily in trends where
Brigham has achieved exploration success, (ii) eliminating substantially all
planned seismic and land expenditures for new projects until its capital
resources can support such additional activity, (iii) seeking to divest certain
producing natural gas and oil properties in an effort to raise capital to reduce
debt borrowings and to redirect capital to drilling projects that have the
potential to generate higher investment returns, (iv) restructuring its
outstanding senior and subordinated debt agreements to provide the Company with
flexibility needed to preserve cash flow to fund its expected near-term
exploration activities, (v) implementing an overhead reduction plan to reduce
general and administrative expenses, and (vi) evaluating opportunities to raise
additional equity capital either through the sales of interests in certain of
its seismic projects or the issuance of equity securities. The Company believes
that the successful execution of these strategic initiatives will provide
Brigham with sufficient capital resources to execute its planned 1999
exploration program and position the Company to realize the significant value it
believes it has captured in its inventory of 3-D seismic projects and delineated
drilling locations. While the Company has initiated each of these strategic
directives in late 1998 and early 1999, and has effected certain of them to
date, the successful completion of any or all of these efforts to improve the
Company's capital availability within the expected timeframe is uncertain and
will likely have a material impact on the Company's near-term capital
expenditure levels and growth profile.
On March 30, 1999, the Company entered into an agreement with Veritas DGC
Land, Inc. ("Veritas") to exchange 1,002,865 shares of newly issued Brigham
common stock valued at $3.50 per share for approximately $3.5 million of payment
obligations due to Veritas in 1999 for certain seismic acquisition and
processing services previously performed. In addition, this agreement provides
for the payment by Brigham of up to $1 million in future seismic processing
services to be performed by Veritas in newly issued shares of Brigham common
stock valued at $3.50 per share, in the event that the Company does not elect to
pay for such services in cash. The settlement of these future seismic
processing services will be determined on a quarterly basis through December 31,
1999. Brigham considers this arrangement to be beneficial as it will enable the
Company to reduce its working capital commitments and preserve additional cash
flow and capital availability to fund its 1999 drilling program.
CAPITAL RESOURCES
The Company's primary sources of capital have been revolving credit
facility and other debt borrowings, public and private equity financings, the
sale of interests in projects and funds generated by operations. The Company's
primary capital requirements are 3-D seismic acquisition, processing and
interpretation costs, land acquisition costs and drilling expenditures. During
May 1997, the Company completed an initial public offering of common stock of
the Company that generated proceeds of approximately $24 million, net of
offering costs, that were used to repay all outstanding debt ($13.3 million)
under the Company's then existing revolving credit facility and to fund capital
expenditures. In January 1998, the Company entered into a new revolving credit
facility that provided for borrowing availability of $75 million that was used
to repay its then outstanding borrowings under its previous credit facility and
to fund capital expenditures. In August 1998, the Company issued $50 million of
debt and equity securities, including the $40 million of Subordinated Notes,
that generated proceeds of approximately $47.5 million, net of offering costs,
that were used to repay a portion of then outstanding borrowings under the
Credit Facility, thereby increasing the Company's borrowing availability under
its Credit Facility to fund capital expenditures.
Revolving Credit Facility
In January 1998, the Company entered into a new revolving credit agreement
(the "Credit Facility"), which provided for borrowing availability of $75
million. The Company used a portion of the funds available under the Credit
Facility to repay the $32 million in borrowings outstanding at December 31, 1997
under its previous commercial bank credit facility. Principal outstanding under
the Credit Facility is due at maturity on January 26, 2001 with interest due
monthly for base rate tranches or periodically as LIBOR tranches mature. The
annual interest rate for borrowings under the Credit Facility has been either
the lender's base rate or LIBOR plus 2.25%, at the Company's option. The Credit
Facility's borrowing availability was subsequently reduced from $75 million to
$65 million upon the Company's issuance of the Subordinated Notes in August
1998.
In March 1999, the Company and its lenders entered into an amendment to the
Credit Facility. Pursuant to this amendment, the borrowing availability under
the Credit Facility will remain at $65 million until June 1, 1999, when the
borrowing availability will be redetermined by the lenders based on the
Company's then proved reserve value and cash flows. In addition, certain
financial covenants of the Credit Facility have been amended, additional
covenants have been included that place significant restrictions on the
Company's ability to incur certain capital expenditures, the annual interest
rate for borrowings under the Credit Facility has been amended to the lender's
base rate or LIBOR plus 3.00%, and the Company will pay the lenders a $500,000
transaction fee over a ten month period. The Company's obligations under the
Credit Facility are secured by substantially all of the natural gas and oil
properties
- 27 -
30
and other tangible assets of the Company. At March 26, 1999, the Company had $59
million in borrowings outstanding under the Credit Facility, which bear interest
at an annual rate of 7.4%. See Note 5 of Notes to the December 31, 1998
Consolidated Financial Statements.
The Credit Facility has certain financial covenants including current and
interest coverage ratios, as defined. The Company and its lenders effected the
recent amendment to the Credit Facility to enable the Company to comply with
certain financial covenants of the Credit Facility, including the minimum
current ratio, minimum interest coverage ratio and the limitation on capital
expenditures related to seismic and land activities. The Company believes this
most recent amendment is indicative of its lenders' cooperation in the current
oil and natural gas pricing environment. If this pricing environment continues
or deteriorates further beyond the date of redetermination of borrowing
availability, the Company believes its lenders will expect the Company to
substantially reduce its level of borrowing under the Credit Facility. With this
in mind, the Company has initiated the business strategy noted above. Should the
Company be unable to comply with certain of the financial covenants, its lenders
may be unwilling to waive compliance or amend the covenants in the future. In
such instance, the Company's liquidity may be adversely affected, which could in
turn have an adverse impact on the Company's future financial position and
results of operations.
Subordinated Notes
In August 1998, the Company issued $50 million of debt and equity
securities to affiliates of Enron Corp. ("Enron"). Securities issued by the
Company in connection with this financing transaction included: (i) $40 million
of Subordinated Notes, (ii) warrants to purchase 1,000,000 shares of the
Company's common stock at a price of $10.45 per share (the "Warrants"), and
(iii) 1,052,632 shares of the Company's common stock at a price of $9.50 per
share. The approximate $47.5 million in net proceeds received by the Company
from this financing transaction were used to repay a portion of outstanding
borrowings under its Credit Facility, which increased the Company's borrowing
availability under its Credit Facility to fund capital expenditures.
Principal outstanding under the Subordinated Notes is due at maturity on
August 20, 2003. Interest on the Subordinated Notes is payable quarterly at
rates that vary depending upon whether accrued interest is paid in cash or "in
kind" through the issuance of additional Subordinated Notes ("PIK Interest").
Interest shall be paid in cash at interest rates of 12%, 13% and 14% per annum
during years one through three, year four and year five, respectively, of the
term of the Subordinated Notes; provided, however, that if the payment of
interest accrued on the Subordinated Notes in cash would cause a borrowing base
deficiency under the Credit Facility or would cause the Company to be in
violation of any covenant or other restriction set forth in any senior loan
document or any agreement entered into by the Company or subsidiary of the
Company in connection with the Subordinated Notes, the Company may pay PIK
Interest at interest rates of 13%, 14% and 15% per annum during years one
through three, year four and year five, respectively, of the term of the Notes.
The Subordinated Notes rank subordinate in right of payment to Senior
Indebtedness (as defined) and senior to all other financings (other than any
allowed capital leases and purchase money financings) of the Company. The
Subordinated Notes are secured by a second lien against substantially all of the
natural gas and oil properties and other tangible assets of the Company. The
Subordinated Notes may be prepaid at any time, in whole or in part, without
premium or penalty, provided that all partial prepayments must be pro rata to
the various holders of the Subordinated Notes. The Subordinated Notes were
issued pursuant to an indenture (the "Indenture") that contains certain
covenants that, among other things, limit the ability of the Company and its
subsidiaries to incur additional indebtedness, pay dividends, make
distributions, enter into certain sale and leaseback transactions, enter into
certain transactions with affiliates, dispose of certain assets, incur liens,
and engage in mergers and consolidations.
In March 1999, the Company and Chase Bank of Texas, National Association,
as trustee (the "Trustee") for the holders of the Subordinated Notes, entered
into an amendment to the Indenture. This amendment provides the Company with the
option to pay interest due on the Subordinated Notes in kind, for any reason,
through the second quarter of 2000. In addition, certain financial and other
covenants were amended. The amendment also provides for a reduction in the
exercise price per share of the Warrants from $10.45 per share to $3.50 per
share.
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31
The Indenture governing the Subordinated Notes has certain financial
covenants including current and interest coverage ratios, as defined. The
Company and the holders of the Subordinated Notes effected the recent amendment
to the Indenture to enable the Company to comply with certain financial
covenants of the Indenture that parallel those of the Credit Facility, including
the minimum current ratio and the minimum interest coverage ratio. Should the
Company be unable to comply with certain of the financial covenants, the holders
of the Subordinated Notes may be unwilling to waive compliance or amend the
covenants in the future. In such instance, the Company's liquidity may be
adversely affected, which could in turn have an adverse impact on the Company's
future financial position and results of operations.
Cash Flow Analysis
Cash Flows from Operating Activities. Cash flows provided by operating
activities were $13.6 million in 1998, $9.8 million in 1997, and $3.7 million in
1996. The increase in cash flows for 1998 compared to 1997 was due primarily to
an increase in natural gas and oil revenues, net of lease operating expenses,
production taxes and general and administrative expenses, and net changes in
working capital items. The increase in cash flows for 1997 compared to 1996 was
due primarily to an increase in natural gas and oil revenues, net of lease
operating expenses, production taxes and general and administrative expenses.
Cash Flows from Investing Activities. Cash flows used in investing
activities increased to $85.1 million in 1998 compared to $57.3 million in 1997
and $11.8 million in 1996. These increases are directly related to an increase
in capital expenditures related to the Company's exploration and development
activities. Capital expenditures were $84.1 million in 1998, $57.2 million in
1997 and $13.6 million in 1996.
The Company acquired 1,213 gross (968 net) square miles of 3-D seismic in
1998, 1,262 gross (842 net) square miles in 1997, and 655 gross (241 net) square
miles in 1996. The Company's drilling efforts resulted in the completion of 50
wells (26.3 net) in 1998, 45 wells (17.6 net) in 1997 and 42 wells (8.7 net) in
1996, which resulted in aggregate net increases in proved reserve volumes (net
of revisions to previous estimates) of 31.2 Bcfe in 1998, 32.4 Bcfe in 1997, and
11.3 Bcfe in 1996. In addition, the Company sold certain producing properties in
1996 for $2.1 million and acquired certain producing properties and related
interests for $13.5 million in 1997 and $1.0 million in 1998.
Cash Flows from Financing Activities. Cash flows provided by financing
activities for 1998 were $72.3 million, primarily as a result of borrowings
under the Credit Facility, the issuance of the Subordinated Notes and the sale
of $10 million of common stock. Cash flows from financing activities for 1997
were $47.7 million, primarily as a result of borrowings under the Company's
previous credit facility and proceeds from the common stock sold in the
Company's initial public offering. Cash flows from financing activities for 1996
were $7.7 million, primarily as a result of borrowings under the Company's
previous credit facility.
Capital Expenditures
As a result of the Company's limited available capital resources, Brigham
has significantly reduced its planned capital expenditure budget for 1999 from
the Company's previously anticipated levels in an effort to match the its
current and expected future capital resources. The Company's current 1999
capital budget is estimated to be $17.5 million, or approximately 21% of 1998
expenditures. The Company's budgeted 1999 capital expenditures consist of
approximately $10 million to drill an estimated 20 to 25 gross wells, $3.5
million for seismic and land costs, consisting primarily of previous year
commitments and obligations to acquire 3-D data and acreage, and $4 million for
capitalized general and administrative expenses and other fixed asset
expenditures. Brigham expects that its 1999 drilling expenditures will be
allocated approximately 50% to its Anadarko Basin province and 50% to its Gulf
Coast province, and such expenditures will be devoted to the drilling of the
highest grade prospects in the Company's inventory of identified potential
drilling locations. The Company intends to fund these budgeted capital
expenditures through a combination of cash flow from operations, available
borrowings under its Credit Facility and the sales of certain assets (including
the potential divestitures of certain producing property packages from among its
Anadarko Basin properties and interests in certain 3-D seismic projects). In
addition to these sources of capital, the Company is also evaluating
opportunities to raise additional capital to enable it to increase its planned
capital expenditures for drilling in 1999. However, since the Company's capital
availability during 1999 will depend to a large extent on the
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32
Company's success raising additional financing through its planned and potential
strategic initiatives, the Company's actual 1999 capital expenditures may differ
from its current estimates. In the event additional financing is not available
in the amounts or timing needed, the Company may be required to curtail its
planned exploration activities in 1999 and take further measures to reduce the
size and scope of its business. See "Item 2. Properties -- Primary Exploration
Provinces."
OTHER MATTERS
Hedging Activities
The Company believes that hedging, although not free of risk, allows the
Company to reduce its exposure to natural gas and oil sales price fluctuations
and thereby to achieve more predictable cash flows. However, hedging
arrangements, when utilized, limit the benefit to the Company of increases in
the prices of the hedged commodity. Moreover, the Company's hedging arrangements
apply only to a portion of its production and provide only partial price
protection against declines in commodity prices. The Company expects that the
amount of its hedges will vary from time to time. See "-- Risk Factors -- Risk
of Hedging Activities" and "Item 7A. Quantitative and Qualitative Disclosures
About Market Risk."
In 1995 the Company, in an attempt to reduce its sensitivity to volatile
commodity prices, began using crude oil swap arrangements resulting in a fixed
price over a period of six months. Total oil purchased and sold subject to swap
arrangements entered into by the Company was 118,150 Bbls in 1996 and 54,900
Bbls in 1995. The Company accounts for all these transactions as hedging
activities and, accordingly, adjusts the price received for natural gas and oil
production during the period the hedged transactions occur. Adjustments to the
price received for oil under these swap arrangements resulted in an increase in
oil revenues of $40,849 in 1995 and decreases in oil revenues of $301,280 in
1996 and $6,191 in 1997. As of December 31, 1997, the Company had no hedging
contracts outstanding.
In 1998, the Company began using natural gas swap arrangements in an
attempt to reduce its sensitivity to volatile commodity prices as its production
base became increasingly weighted toward natural gas. Pursuant to these
arrangements the Company exchanges a floating market price for a fixed contract
price. Payments are made by the Company when the floating price exceeds the
fixed price for a contract month and payments are received by the Company when
the fixed price exceeds the floating price. Settlements of these swaps are based
on the difference between the ANR Pipeline Co.-Oklahoma index price (as
published in Inside FERC's Gas Market Report) for a contract month and the fixed
contract price for the same month.
The following table summarizes the Company's natural gas swap arrangements
entered into from February 1998 through March 1999:
DAILY
DAILY AVERAGE
VOLUMES TOTAL VOLUMES HEDGED (MMBTU) FIXED
HEDGED --------------------------------------------- CONTRACT PRICE
(MMBTU) MONTHLY TERM 1998 1999 2000 2001 ($/MMBTU)(1)
-------- -------------------------- --------- ---------- ---------- ---------- --------------
Contract #1 10,000 April 1998 - October 1999 2,750,000 3,040,000 $2.163
Contract #2 5,000 April 1999 - October 1999 1,070,000 $2.015
Contract #3 15,000 November 1999 - April 2001 915,000 5,490,000 1,800,000 $2.065
- -----------------
(1) Based on the ANR Pipeline Co.-Oklahoma index price as published in Inside
FERC's Gas Market Report.
For the year ended December 31, 1998, the Company realized an increase in
revenues attributable to natural gas hedges of $555,240.
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33
Effects of Inflation and Changes in Prices
The Company's results of operations and cash flows are affected by changing
natural gas and oil prices. If the price of natural gas and oil increases
(decreases), there could be a corresponding increase (decrease) in revenues as
well as the operating costs that the Company is required to bear for operations.
Inflation has had a minimal effect on the Company.
Environmental and Other Regulatory Matters
The Company's business is subject to certain federal, state and local laws
and regulations relating to the exploration for and the development, production
and marketing of natural gas and oil, as well as environmental and safety
matters. Many of these laws and regulations have become more stringent in recent
years, often imposing greater liability on a larger number of potentially
responsible parties. Although the Company believes it is in substantial
compliance with all applicable laws and regulations, the requirements imposed by
laws and regulations are frequently changed and subject to interpretation, and
the Company is unable to predict the ultimate cost of compliance with these
requirements or their effect on its operations. Any suspensions, terminations or
inability to meet applicable bonding requirements could materially adversely
affect the Company's financial condition and operations. Although significant
expenditures may be required to comply with governmental laws and regulations
applicable to the Company, compliance has not had a material adverse effect on
the earnings or competitive position of the Company. Future regulations may add
to the cost of, or significantly limit, drilling activity. See "-- Risk Factors
- -- Compliance with Environmental Regulations," "Item 1. Business -- Governmental
Regulation" and "Item 1. Business -- Environmental Matters."
Year 2000 Issues
Many computer software systems, as well as certain hardware and equipment
using date-sensitive data, were structured to use a two-digit date field meaning
that they may not be able to properly recognize dates in the year 2000. The
Company has developed a plan to address this issue and is taking steps to review
its information technology systems, such as computer hardware and software, as
well as non information technology systems, including computer controlled
equipment and electronic devices used to operate equipment involved in
processing and interpreting 3-D seismic data.
The Company has completed the initial phases of its plan by identifying all
computerized systems and substantially completing an inventory of its equipment
and component parts. Both information technology and non information technology
systems may contain embedded technology, which complicates the Company's Year
2000 identification, assessment, remediation and testing efforts. The Company
continues to inventory its equipment and facilities to determine if they contain
embedded date-sensitive technology. The Company is currently reviewing all of
its systems to determine which are not Year 2000 compliant and will need to be
replaced or modified. This current phase includes comparisons of inventory to
manufacturer's information and/or performance testing. If problems are
identified, the Company will undertake remediation, replacement or alternative
procedures for non-compliant equipment or facilities on a business priority
basis. The Company's identification and assessment efforts to date have not
identified any computer equipment or software it currently uses which will
require replacement or modification, except that one of the word processing
software programs the Company uses may be non-compliant and may need to be
discontinued or upgraded. In addition, in the ordinary course of replacing
computer equipment and software, the Company attempts to obtain replacements
that are Year 2000 compliant. The Company currently anticipates that its
identification, assessment, remediation and testing efforts will continue and,
depending upon the results of the assessment efforts, be completed during the
first three quarters of 1999.
As of December 31, 1998, all costs incurred by the Company in connection
with its Year 2000 compliance efforts were included within the Company's normal
general and administrative expenses (for example, regular maintenance of
software programs). The Company is currently expensing as incurred all costs
related to the assessment and remediation of the Year 2000 issue, and these
costs are being funded through operating cash flow. However, in certain
instances the Company may determine that replacing existing equipment may be
appropriate and may capitalize such replacements. The Company is unable
currently to estimate the amount of its total out-of-pocket costs to become
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34
Year 2000 compliant, but the Company currently expects that such costs will not
have a material adverse effect on the Company's financial condition, operations
or liquidity.
The foregoing timetable and assessment of costs to become Year 2000
compliant reflect management's current best estimates. These estimates are based
on many assumptions, including assumptions about the cost, availability and
ability of resources to locate, remediate and modify affected systems, equipment
and facilities. Based upon its activities to date, the Company does not
currently believe that these factors will cause results to differ significantly
from those estimated. However, the Company cannot reasonably estimate the
potential impact on its financial condition and operations if key third parties
including, among others, suppliers, contractors, joint venture partners,
financial institutions, customers and governments do not become Year 2000
compliant on a timely basis. The Company is currently identifying third parties
whose business significantly impacts the Company, has contacted some significant
third parties to determine the extent to which interfaces with such entities are
vulnerable to Year 2000 issues, and will contact others as it completes the
identification phase.
In the event that the Company is unable to complete the remediation or
replacement of its critical systems, facilities and equipment, establish
alternative procedures in a timely manner, or if those with whom the Company
conducts business are unsuccessful in implementing timely solutions, Year 2000
issues could have a material adverse effect on the Company's liquidity and
results of operations. At this time, the potential effect in the event the
Company and/or third parties are unable to timely resolve their Year 2000
problems is not determinable. A contingency plan has not been developed for
dealing with the most reasonably likely worst case scenario, and such scenario
has not yet been clearly identified. However, the Company currently believes
that it will be able to resolve its own Year 2000 issues in a timely manner.
The disclosure set forth in this section is provided pursuant to Securities
Act Release No. 33-7558. As such it is protected as a forward-looking statement
under the Private Securities Litigation Reform Act of 1995. See "Forward-Looking
Statements." This disclosure is also subject to protection under the Year 2000
Information and Readiness Disclosure Act of 1998, Public Law 105-271, as a "Year
2000 Statement" and "Year 2000 Readiness Disclosure" as defined therein.
Recent Accounting Pronouncements
In June 1997, the Financial Accounting Standards Board (the "FASB") issued
SFAS No. 130, "Reporting Comprehensive Income" which established standards for
reporting, in addition to net income, comprehensive income and its components.
Adoption of this standard has no impact on the Company's financial statements.
In June 1997, the FASB issued SFAS No. 131, "Disclosure about Segments of
an Enterprise and Related Information," which the Company adopted in the first
quarter of 1998. As all of the Company's natural gas and oil properties and
related operations are located in the United States, management has determined
that the Company has one reportable segment.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," which is effective for fiscal years
beginning after June 15, 1999. The Company is currently assessing the impact
adoption of this standard will have on its financial statement presentation.
FORWARD LOOKING INFORMATION
Brigham or its representatives may make forward looking statements, oral or
written, including statements in this report, press releases and filings with
the SEC, regarding estimated future net revenues from oil and natural gas
reserves and the present value thereof, planned capital expenditures (including
the amount and nature thereof), increases in oil and gas production, the number
of wells the Company anticipates drilling through 1999 and the Company's
financial position, business strategy and other plans and objectives for future
operations. Although the Company believes that the expectations reflected in
these forward looking statements are reasonable, there can be no assurance that
the actual results or developments anticipated by the Company will be realized
or, even if substantially realized, that they will have the expected effects on
its business or operations. Among the factors that could cause
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35
actual results to differ materially from the Company's expectations are general
economic conditions, inherent uncertainties in interpreting engineering data,
operating hazards, delays or cancellations of drilling operations for a variety
of reasons, competition, fluctuations in oil and gas prices, the ability of the
Company to successfully integrate the business and operations of acquired
companies, government regulations and other factors set forth among the risk
factors noted below or in the description of the Company's business in Item 1 of
this report. All subsequent oral and written forward looking statements
attributable to the Company or persons acting on its behalf are expressly
qualified in their entirety by these factors. The Company assumes no obligation
to update any of these statements.
RISK FACTORS
Effects of Leverage. The Company had long-term debt outstanding of $99
million (principal amount) as of December 31, 1998 and $100.3 million (principal
amount) as of March 26, 1999. The Indenture limits the amounts of additional
debt borrowings, including borrowings under the Credit Facility or other Senior
Indebtedness (as defined). However, the Indenture permits the Company to borrow
under the Credit Facility up to the lesser of $75 million or the borrowing base
under the Credit Facility ($65 million as of December 31, 1998 and March 26,
1999), which would provide the Company with the ability to borrow up to $6
million of additional indebtedness under its Credit Facility as of December 31,
1998 and March 26, 1999. In addition, the Indenture allows the Company to borrow
up to $25 million of future subordinated indebtedness that is pari passu in
right of payment with the Subordinated Notes if the holders of the Subordinated
Notes have been given a first look and right to make a proposal for such
subordinated indebtedness.
The Company's level of indebtedness will have several important effects on
its operations, including (i) a substantial portion of the Company's cash flow
from operations will be dedicated to the payment of interest on its indebtedness
and will not be available for other purposes; (ii) the covenants contained in
the Credit Facility and the Indenture limit its ability to borrow additional
funds or to dispose of assets and may affect the Company's flexibility in
planning for, and reacting to, changes in business conditions and (iii) the
Company's ability to obtain additional financing in the future for working
capital, capital expenditures, acquisitions, general corporate purposes or other
purposes may be impaired. Moreover, future exploration, development or
acquisition activities may require the Company to alter its capitalization
significantly. These changes in capitalization may significantly alter the
leverage of the Company. The Company's ability to meet its debt service
obligations and to reduce its total indebtedness will be dependent upon the
Company's future performance, which will be subject to general economic
conditions and to financial, business and other factors affecting the operations
of the Company, many of which are beyond its control. There can be no assurance
that the Company's future performance will not be adversely affected by such
economic conditions and financial, business and other factors. See "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity" and "-- Capital Resources."
Substantial Capital Requirements; Limited Current Liquidity. The Company
makes and will continue to make substantial capital expenditures in its
exploration and development projects. The Company's available capital resources
at March 26, 1999 are limited and not sufficient to fund its planned working
capital needs and capital expenditures for 1999. The Company intends to finance
these working capital needs and planned capital expenditures with cash flow from
operations, borrowings available under the Credit Facility, the potential sales
of interests in certain producing properties and 3-D seismic projects and the
potential issuance of additional equity securities. Additional financing will be
required in the future to fund the Company's exploratory and developmental
drilling and 3-D seismic acquisition activities at currently budgeted levels. No
assurance can be given as to the availability or terms of any such additional
financing that may be required or that financing will continue to be available
under the existing or new financing arrangements. If additional capital
resources are not available to the Company, its drilling and other activities
may be curtailed and its business, financial condition and results of operations
could be materially adversely affected. See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Liquidity" and " --
Capital Resources."
Dependence on Exploratory Drilling Activities. The Company's revenues,
operating results and future rate of growth are highly dependent upon the
success of its exploratory drilling program. Exploratory drilling involves
numerous risks, including the risk that no commercially productive natural gas
or oil reservoirs will be encountered. The cost of drilling, completing and
operating wells is often uncertain, and drilling operations may be curtailed,
delayed or canceled as a result of a variety of factors, including unexpected
drilling conditions, pressure or
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36
irregularities in formations, equipment failures or accidents, adverse weather
conditions, compliance with governmental requirements and shortages or delays in
the availability of drilling rigs and the delivery of equipment. Despite the use
of 3-D seismic and other advanced technologies, exploratory drilling remains a
speculative activity. Even when fully utilized and properly interpreted, 3-D
seismic data and other advanced technologies only assist geoscientists in
identifying subsurface structures and do not enable the interpreter to know
whether hydrocarbons are in fact present in those structures. In addition, the
use of 3-D seismic data and other advanced technologies requires greater
predrilling expenditures than traditional drilling strategies, and the Company
could incur losses as a result of such expenditures. The Company's future
drilling activities may not be successful. There can be no assurance that the
Company's overall drilling success rate or its drilling success rate for
activity within a particular province will not decline. Unsuccessful drilling
activities could have a material adverse effect on the Company's results of
operations and financial condition. The Company often gathers 3-D seismic data
over large areas. The Company's interpretation of data delineates those portions
of an area desirable for drilling. Therefore, the Company may choose not to
acquire option and lease rights prior to acquiring seismic and, in many cases,
the Company may identify a drilling location before seeking option or lease
rights in the location. Although the Company has identified numerous potential
drilling locations, there can be no assurance that they will ever be leased or
drilled or that natural gas or oil will be produced from these or any other
potential drilling locations.
Volatility of Oil and Natural Gas Prices. The Company's revenues, operating
results and future rate of growth are highly dependent upon the prices received
for the Company's oil and natural gas. Historically, the markets for oil and
natural gas have been volatile and are likely to continue to be volatile in the
future. Various factors beyond the control of the Company will affect prices of
its oil and natural gas, including worldwide and domestic supplies of oil and
natural gas, the ability of the members of the Organization of Petroleum
Exporting Countries to agree to and maintain oil price and production controls,
political instability or armed conflict in oil-producing regions, the price and
level of foreign imports, the level of consumer demand, the price and
availability of alternative fuels, the availability of pipeline capacity,
weather conditions, domestic and foreign governmental regulations and taxes, and
the overall economic environment. During 1998, the high and low prices for oil
on the NYMEX were $17.82 per Bbl and $10.72 per Bbl, and the high and low prices
for natural gas on the NYMEX were $2.69 per MMBtu and $1.65 per MMBtu. The
recent decline in oil prices is generally thought to be caused primarily by an
oversupply of worldwide crude oil inventory created, in part, by unusually warm
winters in the United States and Europe in 1997 and 1998, an announced increase
in crude oil production quotas for OPEC countries in late 1997 and a possible
decline in demand in certain Asian markets. The recent decline in natural gas
prices is generally thought to be caused primarily by an oversupply of domestic
natural gas inventory created, in part, by reduced demand for natural gas due to
unusually warm winters in the United States in 1997 and 1998. It is impossible
to predict future oil and natural gas price movements with certainty. If such
declines in the NYMEX crude oil or natural gas prices worsen or persist for a
protracted period, it would adversely affect the Company's revenues, net income
and cash flows from operations. Also, if these prices maintain their present
level for an extended time period or decline further, the Company may delay or
postpone certain of its capital projects. Declines in oil and natural gas prices
may materially adversely affect the Company's financial condition, liquidity,
ability to finance planned capital expenditures and results of operations. Lower
oil and natural gas prices also may reduce the amount of oil and natural gas
that the Company can produce economically. Any significant decline in the price
of natural gas or oil would adversely affect the Company's revenues and
operating income and may require a reduction in the carrying value of the
Company's oil and natural gas properties. See "Item 1. Business -- Competition"
and "Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations".
Historical Operating Losses and Variability of Operating Results. The
Company had net losses of approximately $1.3 million in 1994, $1.6 million in
1995, $450,000 in 1996, $1.1 million (including a net $1.2 million non-cash
deferred income tax charge incurred in connection with the Company's conversion
from a partnership to a corporation) in 1997, and $33.3 million (including a
$24.8 million non-cash writedown in the carrying value of its natural gas and
oil properties) in 1998. The Company has incurred net losses in each year of
operation, and there can be no assurance that the Company will be profitable in
the future. At December 31, 1998, the Company's accumulated earnings were a
deficit of $33.4 million and its total stockholders' equity was $24.7 million.
In addition, the Company's future operating results may fluctuate significantly
depending upon a number of factors, including industry conditions, prices of oil
and natural gas, rates of drilling success, rates of production from completed
wells and the timing and amount of capital expenditures. This variability could
have a material adverse effect on the Company's business, financial
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37
condition and results of operations. In addition, any failure or delay in the
realization of expected cash flows from operating activities could limit the
Company's ability to invest and participate in economically attractive projects.
See "Item 6. Selected Financial Data" and "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations."
Reserve Replacement Risk. In general, production from oil and natural gas
properties declines as reserves are depleted, with the rate of decline depending
on reservoir characteristics. Except to the extent the Company conducts
successful exploration and development activities or acquires properties
containing proved reserves, or both, the proved reserves of the Company will
decline as reserves are produced. The Company's future oil and natural gas
production is highly dependent upon its ability to economically find, develop or
acquire reserves in commercial quantities. The business of exploring for or
developing reserves is capital intensive. To the extent cash flow from
operations is reduced and external sources of capital become limited or
unavailable, the Company's ability to make the necessary capital investment to
maintain or expand its asset base of oil and natural gas reserves would be
impaired. The Company participates in a percentage of its wells as a
non-operator. The failure of an operator of the Company's wells to adequately
perform operations, or an operator's breach of the applicable agreements, could
adversely impact the Company. In addition, there can be no assurance that the
Company's future exploration and development activities will result in
additional proved reserves or that the Company will be able to drill productive
wells at acceptable costs. Furthermore, although the Company's revenues could
increase if prevailing prices for oil and natural gas increase significantly,
the Company's finding and development costs could also increase. See "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations."
Operating Hazards and Uninsured Risks. The Company's operations are subject
to hazards and risks inherent in drilling for and producing and transporting oil
and natural gas, such as fires, natural disasters, explosions, encountering
formations with abnormal pressures, blowouts, cratering, pipeline ruptures and
spills, any of which can result in the loss of hydrocarbons, environmental
pollution, personal injury claims and other damage to properties of the Company
and others. As protection against operating hazards, the Company maintains
insurance coverage against some, but not all, potential losses. The Company may
elect to self-insure if management believes that the cost of insurance, although
available, is excessive relative to the risks presented. The Company generally
maintains insurance for the hazards and risks inherent in drilling for and
producing and transporting oil and natural gas and believes this insurance is
adequate. Nevertheless, the occurrence of an event that is not covered, or not
fully covered, by insurance could have a material adverse effect on the
Company's financial condition and results of operations. In addition, pollution
and environmental risks generally are not fully insurable. See "Item 2. Business
and Properties -- Operating Hazards and Uninsured Risks" and "
Uncertainty of Reserve Information and Future Net Revenue Estimates.
Numerous uncertainties are inherent in estimating quantities of proved reserves
and their values, including many factors beyond the Company's control. The
reserve information in herein is an estimate only. Although the Company believes
these estimates are reasonable, reserve estimates are imprecise and are expected
to change as additional information becomes available. Estimates of oil and
natural gas reserves by necessity are projections based on engineering data, and
uncertainties are inherent in the interpretation of this data, the projection of
future rates of production and the timing of development expenditures. Reserve
engineering is a subjective process of estimating underground accumulations of
oil and natural gas that are difficult to measure. The accuracy of any reserve
estimate is a function of the quality of available data, engineering and
geologic interpretation, and judgment. Estimates of economically recoverable oil
and natural gas reserves and of future net cash flows depend upon a number of
variable factors and assumptions, such as historical production from the area
compared with production from other producing areas, the assumed effects of
regulations by governmental agencies, and assumptions concerning future oil and
natural gas prices, future operating costs, severance and excise taxes,
development costs and workover and remedial costs, all of which may in fact vary
considerably from actual results. For these reasons, estimates of the
economically recoverable quantities of oil and natural gas attributable to any
particular group of properties, classifications of reserves based on risk of
recovery, and estimates of the future net cash flows may vary substantially.
Moreover, there can be no assurance that the Company's reserves will ultimately
be produced or that the Company's proved undeveloped reserves will be developed
within the periods anticipated. Any significant variance in the assumptions
could materially affect the estimated quantity and value of the Company's
reserves. Actual production, revenues and expenditures with respect to the
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Company's reserves will likely vary from estimates, and such variances may be
material. See "Item 2. Business and Properties -- Oil and Natural Gas Reserves."
The Present Value of Future Net Revenues referred to herein should not be
construed as the current market value of the estimated oil and natural gas
reserves attributable to the Company's properties. In accordance with applicable
requirements of the SEC, the estimated discounted future net cash flows from
proved reserves are 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. Actual future net cash flows also will be affected by factors such as the
amount and timing of actual production, supply and demand for oil and natural
gas, curtailments or increases in consumption by gas purchasers, and changes in
governmental regulations or taxation. The timing of actual future net cash flows
from proved reserves, and thus their actual present value, will be affected by
the timing of both the production and the incurrence of expenses in connection
with development and production of oil and natural gas properties. In addition,
the 10% discount factor, which must be used to calculate discounted future net
cash flows for SEC 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.
Competition. The Company operates in the highly competitive areas of oil
and natural gas exploration, exploitation, acquisition and production with other
companies. In seeking to acquire desirable producing properties or new leases
for future exploration and in marketing its oil and natural gas production, as
well as in seeking to acquire the equipment and expertise necessary to operate
and develop those properties, the Company faces intense competition from a large
number of independent, technology-driven companies as well as both major and
other independent oil and natural gas companies. Many of these competitors have
financial and other resources substantially in excess of those available to the
Company. The effects of this highly competitive environment could have a
material adverse effect on the Company. See "Item 1. Business -- Competition."
Compliance with Government Regulations. The Company's business is subject
to federal, state and local laws and regulations relating to the exploration
for, and the development, production and marketing of, oil and natural gas, as
well as safety matters. Although the Company believes it is in substantial
compliance with all applicable laws and regulations, legal requirements are
frequently changed and subject to interpretation, and the Company is unable to
predict the ultimate cost of compliance with these requirements or their effect
on its operations. Significant expenditures may be required to comply with
governmental laws and regulations. See "Item 1. Business -- Governmental
Regulation."
Compliance with Environmental Regulations. The Company's operations are
subject to complex environmental laws and regulations adopted by federal, state
and local governmental authorities. Environmental laws and regulations are
frequently changed. The implementation of new, or the modification of existing,
laws or regulations could have a material adverse effect on the Company. The
discharge of natural gas, oil, or other pollutants into the air, soil or water
may give rise to significant liabilities on the part of the Company to the
government and third parties and may require the Company to incur substantial
costs of remediation. No assurance can be given that existing environmental laws
or regulations, as currently interpreted or reinterpreted in the future, or
future laws or regulations will not materially adversely affect the Company's
results of operations and financial condition. See "Item 1. Business --
Environmental Matters."
Risk of Hedging Activities. In an attempt to reduce its sensitivity to
energy price volatility, the Company uses swap arrangements that generally
result in a fixed price over a period of six to eighteen months. If the
Company's reserves are not produced at rates equivalent to the hedged position,
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. 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 natural
gas prices. Additionally, hedging contracts limit the benefits the Company will
realize if actual prices rise above the contract prices. In addition, hedging
contracts are subject to the risk that the other party may prove unable or
unwilling to perform its obligations
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under such contracts. Any significant nonperformance could have a material
adverse financial effect on the Company. For the year ended December 31, 1998,
the Company realized an increase in revenues attributable to natural gas hedges
of $555,240. See "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Other Matters -- Hedging Activities" and
"Item 7A. Quantitative and Qualitative Disclosures About Market Risk."
Marketability of Production. The marketability of the Company's production
depends in part upon the availability, proximity and capacity of natural gas
gathering systems, pipelines and processing facilities. The Company generally
delivers natural gas through gas gathering systems and gas pipelines that it
does not own. Federal and state regulation of oil and natural gas production and
transportation, tax and energy policies, changes in supply and demand and
general economic conditions all could adversely affect the Company's ability to
produce and market its oil and natural gas. Any dramatic change in market
factors could have a material adverse effect on the Company.
Dependence on Key Personnel. The Company has assembled a team of
geologists, geophysicists and engineers having considerable experience applying
3-D imaging technology. The Company is dependent upon the knowledge, skills and
experience of these experts to provide 3-D imaging and assist the Company in
reducing the risks associated with its participation in oil and natural gas
exploration projects. In addition, the success of the Company's business also
depends to a significant extent upon the abilities and continued efforts of its
management, particularly Ben M. Brigham, the Company's Chief Executive Officer,
President and Chairman of the Board. The Company has an employment agreement
with Ben M. Brigham, but does not have an employment agreement with any of its
other employees. The Company has key man life insurance on Mr. Brigham in the
amount of $2 million. The loss of services of key management personnel or the
Company's technical experts, or the inability to attract additional qualified
personnel, could have a material adverse effect on the Company's business,
financial condition, results of operations, development efforts and ability to
grow. There can be no assurance that the Company will be successful in
attracting and retaining such executives, geophysicists, geologists and
engineers. See "Item 1. Business -- Exploration Staff" and "Executive Officers
of the Registrant".
Control by Existing Stockholders. As of March 26, 1999, directors,
executive officers and principal stockholders of the Company, and certain of
their affiliates, beneficially owned approximately 63% of the Company's
outstanding Common Stock. Accordingly, these stockholders, as a group, will be
able to control the outcome of stockholder votes, including votes concerning the
election of directors, the adoption or amendment of provisions in the Company's
Certificate of Incorporation or Bylaws and the approval of mergers and other
significant corporate transactions. The existence of these levels of ownership
concentrated in a few persons make it unlikely that any other holder of Common
Stock will be able to affect the management or direction of the Company. These
factors may also have the effect of delaying or preventing a change in the
management or voting control of the Company.
Certain Antitakeover Considerations. The Company's Certificate of
Incorporation authorizes the Board of Directors of the Company to issue up to 10
million shares of preferred stock without stockholder approval and to set the
rights, preferences and other designations, including voting rights, of those
shares as the Board of Directors may determine. These provisions, alone or in
combination with the matters described in "Risk Factors -- Control by Existing
Stockholders," may discourage transactions involving actual or potential changes
of control of the Company, including transactions that otherwise could involve
payment of a premium over prevailing market prices to holders of Common Stock.
The Company also is subject to provisions of the Delaware General Corporation
Law that may make some business combinations more difficult.
Year 2000 Compliance. Many computer software systems, as well as certain
hardware and equipment using date-sensitive data, were structured to use a
two-digit date field meaning that they may not be able to properly recognize
dates in the year 2000. The Company currently expects that any costs necessary
for the Company to become Year 2000 compliant will not have a material adverse
effect on the Company's financial condition, operations or liquidity. However,
the Company cannot reasonably estimate the potential impact on its financial
condition and operations if key third parties including, among others,
suppliers, contractors, joint venture partners, financial institutions,
customers and governments do not become Year 2000 compliant on a timely basis.
There can be no assurance that the Company will be able to complete any
necessary remediation or replacement of its critical systems, facilities and
equipment or establish alternative procedures in a timely manner; that those
with whom the Company
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conduct business will be successful in implementing timely solutions; or that
Year 2000 issues will not have a material adverse effect on the Company's
business, financial position and results of operations. See "Item 7.
Management's Discussion and Analysis of Financial Conditions and Result of
Operations -- Other Matters -- Year 2000 Issues".
Possible Stock Price Volatility. The trading price of the Common Stock and
the price at which the Company may sell securities in the future could be
subject to large fluctuations in response to limited trading volume in the
Company's stock and changes in government regulations, quarterly variations in
operating results, litigation, general market conditions, the prices of natural
gas and oil, announcements by the Company and its competitors, the liquidity of
the Company, the Company's ability to raise additional funds and other events.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
MANAGEMENT OPINION CONCERNING DERIVATIVE INSTRUMENTS
The Company limits its use of derivative instruments principally to
commodity price hedging activities, whereby gains and losses are generally
offset by price changes in the underlying commodity. As a result, management
believes that its use of derivative instruments does not expose the Company to
material risk. The Company's use of derivative instruments for hedging
activities could materially affect the Company's results of operations in
particular quarterly or annual periods since such instruments can limit the
Company's ability to benefit from favorable oil and natural gas price movements.
However, management believes that use of these instruments will not have a
material adverse effect on the Company's financial position or liquidity.
COMMODITY PRICE RISK
The Company's primary commodity market risk exposure is to changes in the
prices related to the sale of its oil and natural gas production. The market
prices for oil and natural gas have been volatile and are likely to continue to
be volatile in the future. As such, the Company employs established policies and
procedures to manage its exposure to fluctuations in the sales prices it
receives for its oil and natural gas production through hedging activities. See
"Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations -- Other Matters -- Hedging Activities."
The Company believes that hedging, although not free of risk, allows the
Company to reduce its exposure to oil and natural gas sales price fluctuations
and thereby to achieve more predictable cash flows. However, hedging
arrangements, when utilized, limit the benefit to the Company of increases in
the prices of the hedged commodity. Moreover, the Company's hedging arrangements
apply only to a portion of its production and provide only partial price
protection against declines in commodity prices. The Company expects that the
amount of its hedges will vary from time to time.
Based on the Company's natural gas swap arrangements outstanding at
December 31, 1998, an adverse change (defined as a hypothetical 10% and 25%
increase in underlying commodity prices for open positions) would lower revenue
and income before taxes by approximately $902,000 and $2.3 million,
respectively, from currently projected levels. Additionally, as the Company
utilizes swap arrangements to hedge anticipated and firmly committed
transactions, a loss in fair value for those instruments is generally offset by
price changes in the underlying commodity. The impact of these price changes are
not reflected in this sensitivity analysis.
INTEREST RATE RISK
The Company does not utilize derivative instruments to protect against
changes in interest rates on debt borrowings. See Note 11 of Notes to
Consolidated Financial Statements for a description of the Company's financial
instruments at December 31, 1998.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Company's Consolidated Financial Statements required by this item are
included on the pages immediately following the Index to Financial Statements
appearing on page F1-1.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
- 39 -
42
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item is incorporated by reference to
information under the caption "Proposal 1 - Election of Directors" and to the
information under the caption "Compliance with Section 16(a) of the Securities
Exchange Act of 1934" in the Company's definitive Proxy Statement (the "1999
Proxy Statement") for its annual meeting of stockholders to be held on May 13,
1999. The 1999 Proxy Statement will be filed with the Securities and Exchange
Commission (the "Commission") not later than 120 days subsequent to December 31,
1998.
Pursuant to Item 401(b) of Regulation S-K, the information required by this
item with respect to executive officers of the Company is set forth in Part I of
this report.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is incorporated herein by reference
to the 1999 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 1998.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item is incorporated herein by reference
to the 1999 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 1998.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
The information required by this item is incorporated herein by reference
to the 1999 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 1998.
- 40 -
43
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Consolidated Financial Statements:
See Index to Consolidated Financial Statements on page F-1.
2. Financial Statement Schedules:
See Index to Consolidated Financial Statements on page F-1.
3. Exhibits: The following documents are filed as exhibits to this
report:
Number Description
- ------ -----------
2.1 -- Exchange Agreement (filed as Exhibit 2.1 to the Company's
Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
3.1 -- Certificate of Incorporation (filed as Exhibit 3.1 to the
Company's Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
3.2 -- Bylaws (filed as Exhibit 3.2 to the Company's Registration
Statement on Form S-1 (Registration No. 333-22491), and
incorporated herein by reference).
4.1 -- Form of Common Stock Certificate (filed as Exhibit 4.1 to the
Company's Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
4.2+ -- Indenture dated as of August 20, 1998 between Brigham
Exploration Company and Chase Bank of Texas, National
Association, as Trustee.
4.2.1++ -- Supplemental Indenture dated as of March 26, 1999 between
Brigham Exploration Company and Chase Bank of Texas, National
Association, as Trustee.
4.3++ -- Form of Warrant Certificate.
4.4 -- Form of Senior Subordinated Secured Note due 2003 (filed as
Exhibit 4.4 to the Company's Registration Statement on Form
S-1 (Registration No. 333-53873), and incorporated herein by
reference).
10.1 -- Agreement of Limited Partnership, dated May 1, 1992, between
Brigham Exploration Company and General Atlantic Partners III,
L.P. as general partners, and Harold D. Carter and GAP-Brigham
Partners, L.P. as limited partners (filed as Exhibit 10.1 to
the Company's Registration Statement on Form S-1 (Registration
No. 333-22491), and incorporated herein by reference).
10.1.1 -- Amendment No. 1 to Agreement of Limited Partnership of
Brigham Oil & Gas, L.P., dated May 1, 1992, by and among
Brigham Exploration Company, General Atlantic Partners III,
L.P., GAP-Brigham Partners, L.P. and Harold D. Carter (filed
as Exhibit 10.1.1 to the Company's Registration Statement on
Form S-1 (Registration No. 333-22491), and incorporated herein
by reference).
10.1.2 -- Amendment No. 2 to Agreement of Limited Partnership of
Brigham Oil & Gas, L.P., dated September 30, 1994, by and
among Brigham Exploration Company, General Atlantic Partners
III, L.P., GAP-Brigham Partners, L.P., Harold D. Carter and
the additional signatories thereto (filed as Exhibit 10.1.2 to
the Company's Registration Statement on Form S-1 (Registration
No. 333-22491), and incorporated herein by reference).
10.1.3 -- Amendment No. 3 to Agreement of Limited Partnership of
Brigham Oil & Gas, L.P., dated August 24, 1995, by and among
Brigham Exploration Company, General Atlantic Partners III,
L.P., GAP-Brigham Partners, L.P., Harold D.
- 41 -
44
Number Description
- ------ -----------
Carter, Craig M. Fleming, David T. Brigham and Jon L. Glass
(filed as Exhibit 10.1.3 to the Company's Registration
Statement on Form S-1 (Registration No. 333-22491), and
incorporated herein by reference).
10.1.4+ -- Amended and Restated Agreement of Limited Partnership of
Brigham Oil & Gas, L.P., dated December 30, 1997 by and among
Brigham, Inc., Brigham Holdings I, L.L.C. and Brigham Holdings
II, L.L.C.
10.2 -- Agreement of Limited Partnership of Venture Acquisitions,
L.P., dated September 23, 1994, by and between Quest
Resources, L.L.C. and RIMCO Energy, Inc. as general partners,
and RIMCO Production Company, Inc., RIMCO Exploration
Partners, L.P. I and RIMCO Exploration Partners, L.P. II, as
limited partners (filed as Exhibit 10.2 to the Company's
Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.3 -- Regulations of Quest Resources, L.L.C. (filed as Exhibit 10.3
to the Company's Registration Statement on Form S-1
(Registration No. 333-22491), and incorporated herein by
reference).
10.4 -- Management and Ownership Agreement, dated September 23, 1994,
by and among Brigham Oil & Gas, L.P., Brigham Exploration
Company, General Atlantic Partners III, L.P., Harold D.
Carter, Ben M. Brigham and GAP- Brigham Partners, L.P. (filed
as Exhibit 10.4 to the Company's Registration Statement on
Form S-1 (Registration No. 333-22491), and incorporated herein
by reference).
10.5* -- Consulting Agreement, dated May 1, 1997, by and between
Brigham Oil & Gas, L.P. and Harold D. Carter (filed as Exhibit
10.4 to the Company's Registration Statement on Form S-1
(Registration No. 33-53873), and incorporated herein by
reference).
10.6* -- Employment Agreement, by and between Brigham Exploration
Company and Ben M. Brigham (filed as Exhibit 10.7 to the
Company's Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.7* -- Form of Confidentiality and Noncompete Agreement between the
Registrant and each of its executive officers (filed as
Exhibit 10.8 to the Company's Registration Statement on Form
S-1 (Registration No. 333-22491), and incorporated herein by
reference).
10.8* -- 1997 Incentive Plan of Brigham Exploration Company (filed as
Exhibit 10.9 to the Company's Registration Statement on Form
S-1 (Registration No. 333- 22491), and incorporated herein by
reference).
10.8.1* -- Form of Option Agreement for certain executive officers (filed
as Exhibit 10.9.1 to the Company's Registration Statement on
Form S-1 (Registration No. 333- 22491), and incorporated
herein by reference).
10.8.2* -- Option Agreement dated as of March 4, 1997, by and between
Brigham Exploration Company and Jon L. Glass (filed as Exhibit
10.9.2 to the Company's Registration Statement on Form S-1
(Registration No. 333-22491), and incorporated herein by
reference).
10.9* -- Incentive Bonus Plan dated as of February 28, 1997 of Brigham,
Inc. and Brigham Oil & Gas, L.P. (filed as Exhibit 10.10 to
the Company's Registration Statement on Form S-1 (Registration
No. 333-22491), and incorporated herein by reference).
10.10 -- Two Bridgepoint Lease Agreement, dated September 30, 1996,
by and between Investors Life Insurance Company of North
America and Brigham Oil & Gas, L.P. (filed as Exhibit 10.14 to
the Company's Registration Statement on Form S- 1
(Registration No. 333-22491), and incorporated herein by
reference).
- 42 -
45
Number Description
- ------ -----------
10.10.1 -- First Amendment to Two Bridge Point Lease Agreement dated
April 11, 1997 between Investors Life Insurance Company of
North America and Brigham Oil & Gas, L.P. (filed as Exhibit
10.9.1 to the Company's Registration Statement on Form S-1
(Registration No. 333-53873), and incorporated herein by
reference).
10.10.2 -- Second Amendment to Two Bridge Point Lease Agreement dated
October 13, 1997 between Investors Life Insurance Company of
North America and Brigham Oil & Gas, L.P. (filed as Exhibit
10.9.2 to the Company's Registration Statement on Form S-1
(Registration No. 333-53873), and incorporated herein by
reference).
10.10.3 -- Letter dated April 17, 1998 exercising Right of First Refusal
to Lease "3rd Option Space" (filed as Exhibit 10.9.3 to the
Company's Registration Statement on Form S-1 (Registration No.
333-53873), and incorporated herein by reference).
10.11 -- Anadarko Basin Seismic Operations Agreement, dated
February 15, 1996, by and between Brigham Oil & Gas, L.P. and
Veritas Geophysical, Ltd. (filed as Exhibit 10.15 to the
Company's Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.11.1 -- Letter Amendment to Anadarko Basin Seismic Operations
Agreement, dated June 10, 1996, between Brigham Oil & Gas,
L.P. and Veritas Geophysical, Ltd. (filed as Exhibit 10.15.1
to the Company's Registration Statement on Form S-1
(Registration No. 333-22491), and incorporated herein by
reference).
10.12 -- Expense Allocation and Participation Agreement, dated April 1,
1996, between Brigham Oil & Gas, L.P. and Gasco Limited
Partnership. (filed as Exhibit 10.16 to the Company's
Registration Statement on Form S-1 (Registration No. 333-
22491), and incorporated herein by reference).
10.12.1 -- Amendment to Expense Allocation and Participation Agreement,
dated October 21, 1996, between Brigham Oil & Gas, L.P. and
Gasco Limited Partnership (filed as Exhibit 10.16.1 to the
Company's Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.13 -- Expense Allocation and Participation Agreement, dated April 1,
1996, between Brigham Oil & Gas, L.P. and Middle Bay Oil
Company, Inc. (filed as Exhibit 10.17 to the Company's
Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.13.1 -- Amendment to Expense Allocation and Participation Agreement,
dated September 26, 1996, between Brigham Oil & Gas, L.P. and
Middle Bay Oil Company, Inc. (filed as Exhibit 10.17.1 to the
Company's Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.13.2 -- Letter Amendment to Expense Allocation and Participation
Agreement, dated May 20, 1996, between Brigham Oil & Gas, L.P.
and Middle Bay Oil Company, Inc. (filed as Exhibit 10.17.2 to
the Company's Registration Statement on Form S-1 (Registration
No. 333-22491), and incorporated herein by reference).
10.14 -- Anadarko Basin Joint Participation Agreement, dated May 1,
1996, by and among Stephens Production Company and Brigham Oil
& Gas, L.P. (filed as Exhibit 10.18 to the Company's
Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.15 -- Anadarko Basin Joint Participation Agreement, dated May 1,
1996, by and between Vintage Petroleum, Inc. and Brigham Oil &
Gas, L.P. (filed as Exhibit 10.19 to the Company's
Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.16 -- Processing Alliance Agreement, dated July 20, 1993, between
Veritas Seismic Ltd. and Brigham Oil & Gas, L.P. (filed as
Exhibit 10.20 to the Company's
- 43 -
46
Number Description
- ------ -----------
Registration Statement on Form S-1 (Registration
No. 333-22491), and incorporated herein by reference).
10.16.1 -- Letter Amendment to Processing Alliance Agreement, dated
November 3, 1994, between Veritas Seismic Ltd. and Brigham Oil
& Gas, L.P. (filed as Exhibit 10.20.1 to the Company's
Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.17 -- Agreement and Assignment of Interest, West Bradley Project,
dated September 1, 1995, by and between Aspect Resources
Limited Liability Company and Brigham Oil & Gas, L.P. (filed
as Exhibit 10.21 to the Company's Registration Statement on
Form S-1 (Registration No. 333-22491), and incorporated herein
by reference).
10.18 -- Agreement and Assignment of Interests in lands located in
Grady County, Oklahoma, West Bradley Project, dated December
1, 1995, by and between Aspect Resources Limited Liability
Company, Brigham Oil & Gas, L.P. and Venture Acquisitions,
L.P. (filed as Exhibit 10.22 to the Company's Registration
Statement on Form S-1 (Registration No. 333-22491), and
incorporated herein by reference).
10.19 -- Agreement and Assignment of Interests, West Bradley Project,
dated December 1, 1995, by and between Aspect Resources
Limited Liability Company and Brigham Oil & Gas, L.P. (filed
as Exhibit 10.23 to the Company's Registration Statement on
Form S-1 (Registration No. 333-22491), and incorporated herein
by reference).
10.20 -- Geophysical Exploration Agreement, Hardeman Project, Hardeman
and Wilbarger Counties, Texas and Jackson County, Oklahoma,
dated March 15, 1993 by and among General Atlantic Resources,
Inc., Maynard Oil Company, Ruja Muta Corporation, Tucker
Scully Interests Ltd., JHJ Exploration, Ltd., Cheyenne
Petroleum Company, Antrim Resources, Inc., and Brigham Oil &
Gas, L.P. (filed as Exhibit 10.24 to the Company's
Registration Statement on Form S- 1 (Registration No.
333-22491), and incorporated herein by reference).
10.21 -- Agreement and Partial Assignment of Interests in OK13-P
Prospect Area, Jackson County, Oklahoma (Hardeman Project),
dated August 1, 1995, by and between Brigham Oil & Gas, L.P.
and Aspect Resources Limited Liability Company (filed as
Exhibit 10.25 to the Company's Registration Statement on Form
S-1 (Registration No. 333-22491), and incorporated herein by
reference).
10.22 -- Agreement and Partial Assignment of Interests in Q140-E
Prospect Area, Hardeman County, Texas (Hardeman Project),
dated August 1, 1995, by and between Brigham Oil & Gas, L.P.
and Aspect Resources Limited Liability Company (filed as
Exhibit 10.26 to the Company's Registration Statement on Form
S-1 (Registration No. 333-22491), and incorporated herein by
reference).
10.23 -- Agreement and Partial Assignment of Interests in Hankins #1
Chappel Prospect Agreement, Jackson County, Oklahoma (Hardeman
Project), dated March 21, 1996, by and between Brigham Oil &
Gas, L.P., NGR, Ltd. and Aspect Resources Limited Liability
Company (filed as Exhibit 10.27 to the Company's Registration
Statement on Form S-1 (Registration No. 333-22491), and
incorporated herein by reference).
10.24 -- Form of Indemnity Agreement between the Registrant and each
of its executive officers (filed as Exhibit 10.28 to the
Company's Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.25 -- Registration Rights Agreement dated February 26, 1997 by and
among Brigham Exploration Company, General Atlantic Partners
III L.P., GAP-Brigham Partners, L.P., RIMCO Partners, L.P. II,
RIMCO Partners L.P. III, and RIMCO Partners, L.P. IV, Ben M.
Brigham, Anne L. Brigham, Harold D.
- 44 -
47
Number Description
- ------ -----------
Carter, Craig M. Fleming, David T. Brigham and Jon L. Glass
(filed as Exhibit 10.29 to the Company's Registration
Statement on Form S-1 (Registration No. 333-22491), and
incorporated herein by reference).
10.26 -- 1997 Director Stock Option Plan (filed as Exhibit 10.30 to the
Company's Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.27 -- Form of Employee Stock Ownership Agreement (filed as Exhibit
10.31 to the Company's Registration Statement on Form S-1
(Registration No. 333-22491), and incorporated herein by
reference).
10.28 -- Agreement and Assignment of Interest in Geophysical
Exploration Agreement, Esperson Dome Project, dated November
1, 1994, by and between Brigham Oil & Gas, L.P. and Vaquero
Gas Company (filed as Exhibit 10.33 to the Company's
Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.29 -- Geophysical Exploration Agreement, Southwest Danbury Project,
Brazoria County, Texas, dated as of July 1, 1996, by and among
UNEXCO, Inc. and Brigham Oil & Gas, L.P. (filed as Exhibit
10.34 to the Company's Registration Statement on Form S-1
(Registration No. 333-22491), and incorporated herein by
reference).
10.30 -- Geophysical Exploration Agreement, Welder Project, Duval
County, Texas, dated as of October 1, 1996, by and among
UNEXCO, Inc. and Brigham Oil & Gas, L.P. (filed as Exhibit
10.35 to the Company's Registration Statement on Form S- 1
(Registration No. 333-22491), and incorporated herein by
reference).
10.31 -- Proposed Trade Structure, RIMCO/Tigre Project, Vermillion
Parish, Louisiana, among Brigham Oil & Gas, L.P., Tigre Energy
Corporation and Resource Investors Management Company (filed
as Exhibit 10.36 to the Company's Registration Statement on
Form S-1 (Registration No. 333-22491), and incorporated herein
by reference).
10.31.1 -- Letter relating to Proposed Trade Structure, RIMCO/Tigre
Project, dated January 31, 1997, from Resource Investors
Management Company to Brigham Oil & Gas, L.P. (filed as
Exhibit 10.36 to the Company's Registration Statement on Form
S- 1 (Registration No. 333-22491), and incorporated herein by
reference).
10.32 -- Anadarko Basin Seismic Operations Agreement II, dated as of
April 1, 1997, by and between Brigham Oil & Gas, L.P. (filed
as Exhibit 10.37 to the Company's Registration Statement on
Form S-1 (Registration No. 333-22491), and
incorporated herein by reference).
10.32.1 -- Letter Amendment to Anadarko Basin Seismic Operations
Agreement II, dated March 20, 1997, between Brigham Oil & Gas,
L.P. and Veritas DGC Land, Inc. (filed as Exhibit 10.37 to the
Company's Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.33 -- Expense Allocation and Participation Agreement II, dated
April 1, 1997, between Brigham Oil & Gas, L.P., and Gasco
Limited Partnership (filed as Exhibit 10.31 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30,
1997, and incorporated herein by reference).
10.36 -- Credit Agreement dated as of January 26, 1998 among Brigham
Oil & Gas, L.P., Bank of Montreal, as Agent, and the lenders
signatory thereto (filed as Exhibit 10.36 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1997, and incorporated herein by reference).
10.36.1+ -- First Amendment to Credit Agreement dated as of August 20,
1998 among Brigham Oil & Gas, L.P., Bank of Montreal, as
Agent, and the lenders signatory thereto.
- 45 -
48
Number Description
- ------ -----------
10.36.2++ -- Second Amendment to Credit Agreement dated as of March 26,
1999 among Brigham Oil & Gas, L.P., Bank of Montreal, as
Agent, and the lenders signatory thereto.
10.37 -- Guaranty Agreement dated January 26, 1998 by Brigham
Exploration Company in favor of Bank of Montreal, as Agent,
and each of the Lenders party to the Credit Agreement (filed
as Exhibit 10.33.1 to the Company's Registration Statement on
Form S-1 (Registration No. 333-53873), and incorporated herein
by reference).
10.37.1 -- First Amendment to Guaranty Agreement dated as of March 30,
1998 between Brigham Exploration Company and Bank of Montreal,
as Agent for the Lenders party to the Credit Agreement (filed
as Exhibit 10.33.2 to the Company's Registration Statement on
Form S-1 (Registration No. 333-53873), and
incorporated herein by reference).
10.37.2+ -- Second Amendment to Guaranty Agreement dated as of August 20,
1998 between Brigham Exploration Company and Bank of Montreal,
as Agent for the Lenders party to the Credit Agreement.
10.37.3++ -- Third Amendment to Guaranty Agreement dated as of March 26,
1999 between Brigham Exploration Company and Bank of Montreal,
as Agent for the Lenders party to the Credit Agreement.
10.38+ -- Securities Purchase Agreement dated as of August 20, 1998
among Brigham Exploration Company, Enron Capital & Trade
Resources Corp. and Joint Energy Development Investments II
Limited Partnership.
10.39+ -- Registration Rights Agreement dated as of August 20, 1998, by
and among Brigham Exploration Company, Enron Capital & Trade
Resources Corp. and Joint Energy Development Investments II
Limited Partnership.
10.39.1++ -- Amendment to Registration Rights Agreement dated as of
March 26, 1999, by and among Brigham Exploration Company,
Enron Capital & Trade Resources Corp., ECT Merchant
Investments Corp. and Joint Energy Development Investments II
Limited Partnership.
10.40+ -- Form of Guaranty for subsidiaries.
10.41++ -- Exchange Agreement dated as of March 30, 1999 by and between
Brigham Exploration Company and Veritas DGC Land, Inc.
10.42++ -- Registration Rights Agreement dated as of March 30, 1999 by
and between Brigham Exploration Company and Veritas DGC Land,
Inc.
21+ -- Subsidiaries of the Registrant.
23.1+ -- Consent of Price Waterhouse LLP, independent public
accountants.
23.2+ -- Consent of Cawley, Gillespie & Associates, Inc., independent
petroleum engineers.
27+ -- Financial Data Schedule.
- ---------------
* Management contract or compensatory plan.
+ Filed herewith
++ Not filed herewith pursuant to Rule 12b-25 under the Act, and to be
filed by amendment.
(b) The following reports on Form 8-K were filed by the Company during the last
quarter of the period covered by this Annual Report on Form 10-K:
None.
- 46 -
49
GLOSSARY OF OIL AND GAS TERMS
The following are abbreviations and definitions of certain terms commonly
used in the oil and gas industry and in this report.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to oil or other liquid hydrocarbons.
Bcf. One billion cubic feet.
Bcfe. One billion cubic feet of natural gas equivalent. In reference to
natural gas, natural gas equivalents are determined using the ratio of 6 Mcf of
natural gas to 1 Bbl of oil, condensate of natural gas liquids.
CAEX. Computer-aided exploration.
Completion. The installation of permanent equipment for the production of
oil or natural gas.
Developed Acreage. The number of acres which are allocated or assignable
to producing wells or wells capable of production.
Development Well. A well drilled within the proved area of an oil or
natural gas reservoir to the depth of a stratigraphic horizon known to be
productive.
Drilling Costs. The costs associated with drilling and completing a well
(exclusive of seismic and land acquisition costs for that well and future
development costs associated with proved undeveloped reserves added by the well)
divided by total proved reserve additions.
Dry Well. A well found to be incapable of producing either oil or natural
gas in sufficient quantities to justify completion of an oil or gas well.
Exploratory Well. A well drilled to find and produce oil or natural 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 and Development Costs. Capital costs incurred in the acquisition,
exploration and development of proved oil and natural gas reserves divided by
total proved reserve additions.
Gross Acres or Gross Wells. The total acres or wells, as the case may be,
in which the Company has a working interest.
MBbl. One thousand barrels of oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet of natural gas.
Mcfe. One thousand cubic feet of natural gas equivalents.
MMBbl. One million barrels of oil or other liquid hydrocarbons.
MMBtu. One million Btu, or British Thermal Units. One British Thermal
Unit is the quantity of heat required to raise the temperature of one pound of
water by one degree Fahrenheit.
MMcf. One million cubic feet of natural gas.
MMcfe. One million cubic feet of natural gas equivalents.
- 47 -
50
Net Acres or Net Wells. Gross acres or wells multiplied, in each case, by
the percentage working interest owned by the Company.
Net Production. Production that is owned by the Company less royalties
and production due others.
Oil. Crude oil, condensate or other liquid hydrocarbons.
Operator. The individual or company responsible for the exploration,
development, and production of an oil or gas well or lease.
Present Value of Future Net Revenues or PV10%. The pretax present value
of estimated future revenues to be generated from the production of proved
reserves calculated in accordance with SEC guidelines, net of estimated
production and future development costs, using prices and costs as of the date
of estimation without future escalation, without giving effect to non-property
related expenses such as general and administrative expenses, debt service and
depreciation, depletion and amortization, and discounted using an annual
discount rate of 10%.
Proved Developed Reserves. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Proved Reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved Undeveloped 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.
Royalty. An interest in an oil and gas lease that gives the owner of the
interest the right to receive a portion of the production from the leased
acreage (or of the proceeds of the sale thereof), but generally does not require
the owner to pay any portion of the costs of drilling or operating the wells on
the leased acreage. Royalties may be either landowner's royalties, which are
reserved by the owner of the leased acreage at the time the lease is granted, or
overriding royalties, which are usually reserved by an owner of the leasehold in
connection with a transfer to a subsequent owner.
Spud. Start drilling a new well (or restart).
Standardized Measure. The aftertax present value of estimated future
revenues to be generated from the production of proved reserves calculated in
accordance with SEC guidelines, net of estimated production and future
development costs, using prices and costs as of the date of estimation without
future escalation, without giving effect to non-property related expenses such
as general and administrative expenses, debt service and depreciation, depletion
and amortization, and discounted using an annual discount rate of 10%.
Success Rate. The number of wells on which production casing has been run
for a completion attempt as a percentage of the number of wells drilled.
2-D Seismic. The method by which a cross-section of the earth's
subsurface is created through the interpretation of reflecting seismic data
collected along a single source profile.
3-D Seismic. The method by which a three dimensional image of the earth's
subsurface is created through the interpretation of reflection seismic data
collected over surface grid. 3-D seismic surveys allow for a more detailed
understanding of the subsurface than do conventional surveys and contribute
significantly to field appraisal, development and production.
Working Interest. An interest in an oil and gas lease that gives the
owner of the interest the right to drill for and produce oil and natural gas on
the leased acreage and requires the owner to pay a share of the costs of
drilling and production operations.
- 48 -
51
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, hereunder duly authorized, as of March 31, 1999.
BRIGHAM EXPLORATION COMPANY
By: /s/ Ben M. Brigham
--------------------------------------
Ben M. Brigham
Chief Executive Officer and President
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below as of March 31, 1999, by the following persons on
behalf of the Registrant and in the capacity indicated.
/s/ Ben M. Brigham
- -------------------------------------------------------
Ben M. Brigham
Chief Executive Officer, President and Chairman of the Board
/s/ Jon L. Glass
- -------------------------------------------------------
Jon L. Glass
Vice President - Exploration and Director
/s/ Craig M. Fleming
- -------------------------------------------------------
Craig M. Fleming
Chief Financial Officer
(principal financial and accounting officer)
/s/ Anne L. Brigham
- -------------------------------------------------------
Anne L. Brigham
Director
/s/ Harold D. Carter
- -------------------------------------------------------
Harold D. Carter
Director
/s/ W. Craig Childers
- -------------------------------------------------------
W. Craig Childers
Director
/s/ Alexis M. Cranberg
- -------------------------------------------------------
Alexis M. Cranberg
Director
/s/ Stephen P. Reynolds
- -------------------------------------------------------
Stephen P. Reynolds
Director
- 49 -
52
INDEX TO FINANCIAL STATEMENTS
PAGE
-----
Financial Statements of Brigham Exploration Company
Report of Independent Accountants............................................................. F1-2
Consolidated Balance Sheets as of December 31, 1998 and 1997.................................. F1-3
Consolidated Statements of Operations for the Years Ended
December 31, 1998, 1997, and 1996.......................................................... F1-4
Consolidated Statements of Stockholders' Equity for the Years Ended
December 31, 1998, 1997, and 1996.......................................................... F1-5
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1998, 1997, and 1996.......................................................... F1-6
Notes to the Consolidated Financial Statements................................................ F1-7
Financial Statements of Brigham Exploration Company Guarantor Subsidiaries*
Report of Independent Accountants............................................................. F2-1
Combined Balance Sheets as of December 31, 1998............................................... F2-2
Combined Balance Sheets as of December 31, 1997............................................... F2-3
Combined Statements of Operations for the Year Ended December 31, 1998........................ F2-4
Combined Statements of Operations for the Year Ended December 31, 1997........................ F2-5
Combined Statements of Equity for the Year Ended December 31, 1998............................ F2-6
Combined Statements of Equity for the Year Ended December 31, 1997............................ F2-7
Combined Statements of Cash Flows for the Year Ended December 31, 1998........................ F2-8
Combined Statements of Cash Flows for the Year Ended December 31, 1997........................ F2-9
Notes to the Combined Financial Statements.................................................... F2-10
As all Brigham Exploration Company subsidiaries fully and unconditionally
guarantee the Senior Subordinated Secured Notes and the Company has no
significant assets other than its investments in its subsidiaries, the
consolidated financial statements are substantially the same as the financial
statements of the subsidiary guarantors and separate financial statements have
been omitted as they would not be meaningful to investors.
Financial statements for the wholly owned subsidiaries whose securities are
pledged as collateral for the Senior Subordinated Notes are included in the
combined financial statements.*
- --------------
*These items are omitted from this Form 10-K pursuant to Rule 12b-25 under
the Act and will be filed by amendment to this Form 10-K.
F1-1
53
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors
and Stockholders of Brigham Exploration Company
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations and changes in stockholders' equity and of
cash flows, after the restatement discussed in Note 12, present fairly, in all
material respects, the financial position of Brigham Exploration Company and its
subsidiaries at December 31, 1998 and 1997, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1998, in conformity with generally accepted accounting principles. These
financial statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
generally accepted auditing standards which require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for the opinion expressed
above.
PricewaterhouseCoopers LLP
Houston, Texas
March 30, 1999
F1-2
54
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands)
December 31,
--------------------
1998 1997
-------- --------
ASSETS
Current assets:
Cash and cash equivalents $ 2,569 $ 1,701
Accounts receivable 7,938 4,909
Prepaid expenses 290 280
-------- --------
Total current assets 10,797 6,890
-------- --------
Natural gas and oil properties, at cost, net 134,317 84,294
Other property and equipment, at cost, net 2,014 1,239
Drilling advances paid 230 78
Other noncurrent assets 3,158 18
-------- --------
$150,516 $ 92,519
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 19,883 $ 11,892
Accrued drilling costs 1,219 2,406
Participant advances received 764 489
Other current liabilities 1,647 726
-------- --------
Total current liabilities 23,513 15,513
-------- --------
Notes payable 59,000 32,000
Senior subordinated notes, net 35,786 --
Other noncurrent liabilities 7,536 507
Deferred income tax liability -- 1,186
Stockholders' equity:
Preferred stock, $.01 par value, 10 million shares
authorized, none issued and outstanding -- --
Common stock, $.01 par value, 30 million shares
authorized, 13,306,206 and 12,253,574 issued and outstanding at
December 31, 1998 and 1997, respectively 133 123
Additional paid-in capital 58,838 44,919
Unearned stock compensation (890) (1,674)
Accumulated deficit (33,400) (55)
-------- --------
Total stockholders' equity 24,681 43,313
-------- --------
$150,516 $ 92,519
======== ========
The Company uses the full cost method to account for its natural gas and oil
properties.
See accompanying notes to the consolidated financial statements.
F1-3
55
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
Year Ended December 31,
----------------------------------
1998 1997 1996
---------- -------- --------
Revenues:
Natural gas and oil sales $ 13,799 $ 9,184 $ 6,141
Workstation revenue 390 637 627
---------- -------- --------
14,189 9,821 6,768
---------- -------- --------
Costs and expenses:
Lease operating 2,172 1,151 726
Production taxes 850 549 362
General and administrative 4,672 3,570 2,199
Depletion of natural gas and oil properties 8,410 2,743 2,323
Depreciation and amortization 413 306 487
Capitalized ceiling impairment 24,847 -- --
Amortization of stock compensation 372 388 --
---------- -------- --------
41,736 8,707 6,097
---------- -------- --------
Operating income (loss) (27,547) 1,114 671
---------- -------- --------
Other income (expense):
Interest income 136 145 52
Interest expense (7,120) (1,017) (373)
Interest expense - related party -- (173) (800)
---------- -------- --------
(6,984) (1,045) (1,121)
---------- -------- --------
Net income (loss) before income taxes (34,531) 69 (450)
Income tax benefit (expense) 1,186 (1,186) --
---------- -------- --------
Net loss $ (33,345) (1,117) $ (450)
========== ======== ========
Net loss per share:
Basic/Diluted $ (2.64) $ (0.10) $ (0.05)
Common shares outstanding:
Basic/Diluted 12,626 11,081 8,929
Unaudited pro forma information (Notes 1 and 2)
Net loss $ (450)
Pro forma Exchange adjustments 275
--------
Pro forma net loss before income taxes (175)
Pro forma income tax benefit 147
--------
Pro forma net loss $ (28)
========
Pro forma net loss per basic/diluted common share $ (0.00)
Pro forma weighted average number of common
basic/diluted shares outstanding 9,170
See accompanying notes to the consolidated financial statements.
F1-4
56
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
(in thousands)
Common Stock Additional Unearned
---------------------- Paid-in Stock Accumulated Predecessor
Shares Amounts Capital Compensation Deficit Capital Total
---------- --------- ---------- ------------ -------------- ------------- -------
Balance,
December 31, 1995 -- $ -- $ -- $ -- $ -- $ 3,694 $ 3,694
Net loss -- -- -- -- -- (450) (450)
---------- --------- ---------- ------------ ------------ ------------- -------
Balance,
December 31, 1996 -- -- -- -- -- 3,244 3,244
Consummation of
the Exchange 8,928,574 90 19,580 -- -- (3,244) 16,426
Issuance of stock
options -- -- 2,576 (2,576) -- -- --
Forfeiture of stock
options -- -- (69) 69 -- -- --
Issuance of common
stock 3,325,000 33 23,894 -- -- -- 23,927
Net loss for
period ended
February 27, 1997 -- -- (4,869) -- -- -- (4,869)
Net income for
period from
February 27, 1997
to Dec. 31, 1997 -- -- 3,807 -- (55) -- 3,752
Amortization of
unearned stock
compensation -- -- -- 833 -- -- 833
---------- --------- ---------- ----------- ------------ ------------- -------
Balance,
December 31, 1997 12,253,574 123 44,919 (1,674) (55) -- 43,313
Net loss -- -- -- -- (33,345) -- (33,345)
Issuance of
common stock 1,052,632 10 9,419 -- -- -- 9,429
Issuance of warrants -- -- 4,500 -- -- -- 4,500
Amortization of
unearned stock
compensation -- -- -- 784 -- -- 784
----------- ---------- ---------- ----------- ------------ ------------- -------
Balance,
December 31, 1998 13,306,206 $ 133 $ 58,838 $ (890) $ (33,400) $ -- $24,681
=========== ========= ========== =========== ============ ============= =======
See accompanying notes to the consolidated financial statements.
F1-5
57
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Year ended December 31,
-----------------------------------
1998 1997 1996
--------- --------- ---------
Cash flows from operating activities:
Net loss $ (33,345) $ (1,117) $ (450)
Adjustments to reconcile net loss to cash
provided by operating activities:
Depletion of natural gas and oil properties 8,410 2,743 2,323
Depreciation and amortization 413 306 487
Capitalized ceiling impairment 24,847 -- --
Amortization of stock compensation 372 388 --
Amortization of deferred loan fees and debt issuance costs 726 -- --
Amortization of discount on senior subordinated notes 286 -- --
Changes in working capital and other items:
Increase in accounts receivable (3,029) (2,213) (1,440)
(Increase) decrease in prepaid expenses (10) (128) 25
Increase in accounts payable 7,991 8,955 1,619
Increase (decrease) in participant advances received 275 (648) 804
Increase in interest payable on senior subordinated notes 507 -- --
Increase in other current liabilities 355 50 60
Increase in deferred interest payable - related party -- 53 320
Increase (decrease) in deferred income tax liability (1,186) 1,186 --
Other noncurrent assets 6 281 (224)
Other noncurrent liabilities 7,004 (50) 186
--------- --------- ---------
Net cash provided by operating activities 13,622 9,806 3,710
--------- --------- ---------
Cash flows from investing activities:
Additions to natural gas and oil properties (84,055) (57,170) (13,612)
Proceeds from the sale of natural gas and oil properties -- 74 2,149
Additions to other property and equipment (868) (545) (41)
(Increase) decrease in drilling advances paid (152) 341 (292)
--------- --------- ---------
Net cash used by investing activities (85,075) (57,300) (11,796)
--------- --------- ---------
Cash flows from financing activities:
Proceeds from issuance of common stock 9,429 23,927 --
Proceeds from issuance of senior subordinated notes
payable and warrants 40,000 -- --
Increase in notes payable 105,800 37,250 8,000
Repayment of notes payable (78,800) (13,250) --
Principal payments on capital lease obligations (236) (179) (269)
Deferred loan fees and debt issuance costs (3,872) -- --
--------- --------- ---------
Net cash provided by financing activities 72,321 47,748 7,731
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents 868 254 (355)
Cash and cash equivalents, beginning of year 1,701 1,447 1,802
--------- --------- ---------
Cash and cash equivalents, end of year $ 2,569 $ 1,701 $ 1,447
========= ========= =========
Supplemental disclosure of cash flow information:
Cash paid during the year for interest $ 5,490 $ 1,679 $ 762
========= ========= =========
Supplemental disclosure of noncash investing and financing activities:
Capital lease asset additions $ 320 $ 403 $ 101
========= ========= =========
See accompanying notes to the consolidated financial statements.
F1-6
58
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND NATURE OF OPERATIONS
Brigham Exploration Company is a Delaware corporation formed on February
25, 1997 for the purpose of exchanging its common stock for the common stock of
Brigham, Inc. and the partnership interests of Brigham Oil & Gas, L.P. (the
"Partnership"). Hereinafter, Brigham Exploration Company and the Partnership are
collectively referred to as "the Company." Brigham, Inc. is a Nevada corporation
whose only asset is its ownership interest in the Partnership. The Partnership
was formed in May 1992 to explore and develop onshore domestic natural gas and
oil properties using 3-D seismic imaging and other advanced technologies. Since
its inception, the Partnership has focused its exploration and development of
natural gas and oil properties primarily in West Texas, the Anadarko Basin and
the onshore Gulf Coast.
Pursuant to an exchange agreement dated February 26, 1997 (the "Exchange
Agreement") and upon the initial filing on February 27, 1997 of a registration
statement with the Securities and Exchange Commission (the "SEC") for the public
offering of common stock (the "Offering"), the shareholders of Brigham, Inc.
transferred all of the outstanding stock of Brigham, Inc. to the Company in
exchange for 3,859,821 shares of common stock of the Company. Pursuant to the
Exchange Agreement, the Partnership's other general partner and the limited
partners also transferred all of their partnership interests to the Company in
exchange for 3,314,286 shares of common stock of the Company. Furthermore, the
holders of the Partnership's subordinated convertible notes transferred these
notes to the Company in exchange for 1,754,464 shares of common stock. These
transactions are referred to as "the Exchange." In completing the Exchange, the
Company issued 8,928,571 shares of common stock to the stockholders of Brigham,
Inc., the partners of the Partnership and the holder of the Partnership's
subordinated notes payable. As a result of the Exchange, the Company now owns
all the partnership interests in the Partnership. In May 1997, the Company sold
3,325,000 shares of its common stock in the Offering at a price of $8.00 per
share.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Accounting
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 may differ from those estimates.
The Exchange has been reflected in the consolidated financial statements of
the Company as a reorganization.
Principles of Consolidation
The accompanying financial statements include the accounts of the Company
and its wholly-owned subsidiaries, and its proportionate share of assets,
liabilities and income and expenses of the limited partnerships in which the
Company, or any of its subsidiaries has a participating interest. All
significant intercompany accounts and transactions have been eliminated.
F1-7
59
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Cash and Cash Equivalents
The Company considers all highly liquid financial instruments with an
original maturity of three months or less to be cash equivalents.
Property and Equipment
The Company uses the full cost method of accounting for its investment in
natural gas and oil properties. Under this method, all acquisition, exploration
and development costs, including certain payroll and other internal costs,
incurred for the purpose of finding natural gas and oil reserves are
capitalized. Internal costs capitalized are directly attributable to
acquisition, exploration and development activities and do not include costs
related to production, general corporate overhead or similar activities. Costs
associated with production and general corporate activities are expensed in the
period incurred.
The capitalized costs of the Company's natural gas and oil properties
plus future development, dismantlement, restoration and abandonment costs (the
"Amortizable Base"), net of estimated of salvage values, are amortized using the
unit-of-production method based upon estimates of total proved reserve
quantities. The Company's capitalized costs of its natural gas and oil
properties, net of accumulated amortization, are limited to the total of
estimated future net cash flows from proved natural gas and oil reserves,
discounted at ten percent, plus the cost of unevaluated properties. There are
many factors, including global events, that may influence the production,
processing, marketing and valuation of natural gas and oil. A reduction in the
valuation of natural gas and oil properties resulting from declining prices or
production could adversely impact depletion rates and capitalized cost
limitations.
All costs directly associated with the acquisition and evaluation of
unproved properties are initially excluded from the Amortizable Base. Upon the
interpretation by the Company of the 3-D seismic data associated with unproved
properties, the geological and geophysical costs related to acreage that is not
specifically identified as prospective are added to the Amortizable Base.
Geological and geophysical costs associated with prospective acreage, as well as
leasehold costs, are added to the Amortizable Base when the prospects are
drilled. Costs of prospective acreage are reviewed annually for impairment on a
property-by-property basis.
At December 31, 1998, a capitalized ceiling impairment of $24.8 million was
recognized. The write down was calculated based on the estimated discounted
present value of future net cash flows from proved natural gas and oil reserves
using prices in effect at December 31, 1998.
Other property and equipment, which primarily consists of 3-D seismic
interpretation workstations, are depreciated on a straight-line basis over the
estimated useful lives of the assets after considering salvage value. Estimated
useful lives are as follows:
Furniture and fixtures.................................. 10 years
Machinery and equipment................................. 5 years
3-D seismic interpretation workstations and software.... 3 years
F1-8
60
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Betterments and major improvements that extend the useful lives are
capitalized, while expenditures for repairs and maintenance of a minor nature
are expensed as incurred.
Revenue Recognition
The Company recognizes natural gas and oil sales from its interests in
producing wells under the sales method of accounting. Under the sales method,
the Company recognizes revenues based on the amount of natural gas or oil sold
to purchasers, which may differ from the amounts to which the Company is
entitled based on its interest in the properties. Gas balancing obligations as
of December 31, 1996, 1997 and 1998 were not significant.
Industry participants in the Company's seismic programs are charged on an
hourly basis for the work performed by the Company on its 3-D seismic
interpretation workstations. The Company recognizes workstation revenue as
service is provided.
Derivative Instruments
Net realized gains or losses and related cash flows arising from the
Company's commodity price swaps (see Note 11) are recognized in the period
incurred as a component of natural gas and oil sales. If subsequent to being
hedged, underlying transactions are determined not to be likely to occur, the
related derivatives gains and losses are recognized in that period as "Other
income."
Stock Based Compensation
The Company measures compensation expense for its stock based incentive
plan using the intrinsic value method and has provided in Note 12 the pro forma
disclosure of the effect on net loss and net loss per common share as if the
fair value based method prescribed by Statement of Financial Accounting
Standards ("SFAS") No. 123, "Accounting for Stock Based Compensation," had been
applied in measuring compensation expense.
Federal and State Income Taxes
Prior to the consummation of the Exchange, there was no income tax
provision included in the financial statements as the Partnership was not a
taxpaying entity. Income and losses were passed through to its partners on the
basis of the allocation provisions established by the partnership agreement.
Upon consummation of the Exchange, the Partnership became subject to federal
income taxes through its ownership by the Company.
In conjunction with the Exchange, the Company recorded a deferred income
tax liability of $5 million to recognize the temporary differences between the
financial statement and tax bases of the assets and liabilities of the
Partnership at the Exchange date, February 27, 1997, given the provisions of
enacted tax laws. Subsequent to this date, the Company elected to record a
step-up in basis of its assets for tax purposes as a result of the Exchange.
Related to this election, the Company recorded a $3.8 million deferred income
tax benefit, resulting in a net $1.2 million deferred income tax charge for the
year ended December 31, 1997.
F1-9
61
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Unaudited Pro Forma Information
Pro forma net loss for the year ended December 31, 1996 reflects the
Exchange, including income taxes that would have been recorded had the
Partnership been a taxable entity. Pro forma exchange adjustments primarily
represent the amortization of the compensation expense related to employee stock
options granted upon the formation of the Company (see Note 12), and the
reduction of interest expense related to the elimination of debt as part of the
Exchange. Pro forma income taxes have been included in the Statement of
Operations pursuant to the rules and regulations of the SEC for instances when a
partnership becomes subject to federal income taxes.
Comprehensive Income
In June 1997, the FASB issued SFAS No. 130, "Reporting Comprehensive
Income." The standard, which was effective for financial statements issued for
periods ending after December 15, 1997, established standards for reporting, in
addition to net income, comprehensive income and its components including, as
applicable, foreign currency items, minimum pension liability adjustments and
unrealized gains and losses on certain investments in debt and equity
securities. Adoption of this Standard has no impact on the Company's financial
statements.
Recent Pronouncements
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." SFAS No. 133 requires that all derivative
instruments be recorded on the balance sheet at fair value. Changes in the fair
value of derivatives are recorded each period in current earnings or other
comprehensive income, depending on whether a derivative is designated as part of
a hedge transaction and, if it is, depending on the type of hedge transaction.
For fair value hedge transactions in which the Company is hedging changes in an
asset's, liability's, or firm commitment's fair value, changes in the fair value
of the derivative instrument will generally be offset in the income statement by
changes in the hedged item's fair value. For cash flow hedge transactions in
which the Company is hedging the variability of cash flows related to a
variable-rate asset, liability, or a forecasted transaction, changes in the fair
value of the derivative instrument will be reported in other comprehensive
income. The gains and losses on the derivative instrument that are reported in
other comprehensive income will be reclassified as earnings in the periods in
which earnings are impacted by the variability of the cash flows of the hedged
item. The ineffective portion of all hedges will be recognized in current period
earnings. The Company must adopt SFAS No. 133 effective January 1, 2000. The
Company is in the process of analyzing the potential impact of this standard on
its financial statements presentation.
3. ACQUISITION
On November 12, 1997, the Company acquired a 50% interest in certain
producing properties in Grady County, Oklahoma (the "Acquisition"). These
properties were formerly owned by Mobil and were acquired by Ward Petroleum. The
acquisition was accounted for as a purchase and the results of operations of the
properties acquired were included in the Company's results of operations
effective September 1, 1997. The purchase price of $13.4 million was financed
primarily through the Company's existing revolving credit facility and was based
on the Company's determination of the fair value of the assets acquired.
F1-10
62
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Pro Forma Information
The following unaudited pro forma statement of operations information has
been prepared to give effect to the Acquisition as if the transaction had
occurred at the beginning of 1996 and 1997. The historical results of operations
have been adjusted to reflect (i) the difference between the acquired
properties' historical depletion and such expense calculated based on the value
allocated to the acquired assets, (ii) the increase in interest expense
associated with the debt issued in the transaction, and (iii) the increase in
federal income taxes related to historical net income attributable to the
properties acquired. The pro forma amounts do not purport to be indicative of
the results of operations that would have been reported had the Acquisition
occurred as of the dates indicated, or that may be reported in the future (in
thousands).
PRO FORMA
YEAR ENDED
DECEMBER 31,
-------------------
1997 1996
-------- -------
Revenues.......................................................................... $ 11,194 $ 8,516
Costs and expenses:
Lease operating and production taxes ....................................... 1,864 1,300
General and administrative ................................................. 3,570 2,199
Depletion of natural gas and oil properties ................................ 3,307 2,791
Depreciation and amortization .............................................. 593 487
Interest expense, net ...................................................... 2,235 2,355
-------- -------
Total costs and expenses ................................................... 11,569 9,132
-------- -------
Net loss before income taxes ..................................................... (375) (616)
Income tax expense ......................................................... 1,035 --
-------- -------
Net loss......................................................................... $ (1,410) $ (616)
======== =======
Net loss per share:
Basic/Diluted.............................................................. $ (0.13) $ (0.07)
======== =======
Common shares outstanding:
Basic/Diluted .............................................................. 11,081 8,929
======== =======
4. PROPERTY AND EQUIPMENT
Property and equipment, at cost, are summarized as follows (in
thousands):
DECEMBER 31,
----------------------------
1998 1997
------------ ------------
Natural gas and oil properties.................................... $ 179,867 $ 96,587
Accumulated depletion............................................. (45,550) (12,293)
------------ ------------
134,317 84,294
------------ ------------
Other property and equipment:
3-D seismic interpretation workstations and software.......... 2,186 1,693
Office furniture and equipment................................ 1,774 1,095
Accumulated depreciation...................................... (1,946) (1,549)
------------ ------------
2,014 1,239
------------ ------------
$ 136,331 $ 85,533
============ ============
F1-11
63
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The accumulated depletion balance for natural gas and oil properties at
December 31, 1998, includes the effect of a capitalized ceiling impairment of
$24.8 million described at Note 2, "Property and Equipment."
The Company sold its interest in certain producing properties for $74,000
during 1997. No gain or loss was recognized on this transaction because the
Company applies the full cost method of accounting for its investment in natural
gas and oil properties.
The Company capitalizes certain payroll and other internal costs directly
attributable to acquisition, exploration and development activities as part of
its investment in natural gas and oil properties over the periods benefited by
these activities. Capitalized costs do not include any costs related to
production, general corporate overhead, or similar activities. During the years
ended December 31, 1996, 1997 and 1998, these capitalized costs amounted to $1.8
million, $3.5 million and $4.6 million, respectively.
5. NOTES PAYABLE AND SENIOR SUBORDINATED NOTES PAYABLE
In April 1996, the Company entered into a revolving credit facility which
provided for borrowings up to $25 million. On November 10, 1997, this facility
was amended and the amount available under the agreement was increased to $75
million. The Company's borrowings under this facility were limited to a
borrowing base determined periodically by the lender. This determination was
based upon the proved reserves of the Company's natural gas and oil properties.
The amounts outstanding under this facility, excluding a $5.4 million
special advance made November 12, 1997, bore interest, at the borrower's option,
at the Base Rate or (i) LIBOR plus 1.75% if the principal outstanding was less
than or equal to 50% of the borrowing base, (ii) LIBOR plus 2.0% if the
principal outstanding was less than or equal to 75% but more than 50% of the
borrowing base, and (iii) LIBOR plus 2.25% if the principal outstanding was
greater than 75% of the borrowing base. The Base Rate is the fluctuating rate of
interest per annum established from time to time by the lender. Interest accrued
on the $5.4 million special advance at 11.50% per annum. The Company also paid a
quarterly commitment fee of 0.5% per annum for the unused portion of the
borrowing base.
In January 1998, the Company entered into a new reserve-based revolving
credit facility (the "Credit Facility"). The Credit Facility originally provided
for borrowings up to $75 million, all of which was immediately available for
borrowing to fund capital expenditures. A portion of the funds available under
the Credit Facility were used to repay in full the debt outstanding under the
Company's previous revolving credit facility. Principal outstanding under the
Credit Facility is due at maturity on January 26, 2001 with interest due monthly
for base rate tranches or periodically as LIBOR tranches mature. Amounts
outstanding under the Credit Facility bore interest at either the lender's Base
Rate or LIBOR plus 2.25%, at the Company's option. The Credit Facility contains
covenants restricting the Company's ability to declare or pay dividends on its
stock. In connection with the origination of the Credit Facility, certain bank
fees and other expenses totaling approximately $1.9 million were recorded as
deferred costs and are amortized over the life of the loan. The Credit
Facility's borrowing base was reduced to $65 million upon issuance of the senior
subordinated notes in August 1998.
F1-12
64
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
In March 1999, the Company and its lenders entered into an amendment to the
Credit Facility. Pursuant to this amendment, the borrowing availability under
the Credit Facility remains at $65 million and the initial borrowing
availability redetermination date was extended from January 31, 1999 to June 1,
1999, when the borrowing availability will be redetermined by the lenders based
on the Company's then proved reserve value and cash flows. To the extent that
the amounts outstanding under the Credit Facility exceed the borrowing
availability at the redetermination date, the Company may be required to repay
such excess under provision of the amendment. In addition, certain financial
covenants have been amended, additional covenants have been included that place
significant restrictions on the Company's ability to make certain capital
expenditures, and the annual interest rate for borrowings under the Credit
Facility is revised to the lender's base rate or LIBOR plus 3.0% and the Company
will pay the lender a $500,000 transaction fee over a ten month period. The
Company's obligations under the Credit Facility are secured by substantially all
of the natural gas and oil properties and other tangible assets of the Company.
In August 1998, upon the filing of a registration statement with the SEC,
the Company issued $50 million of debt and equity securities to two affiliated
institutional investors. The financing transaction consisted of the issuance of
$40 million of senior subordinated secured notes (the "Notes") with warrants
(the "Warrants") to purchase the Company's common stock and the sale of $10
million of the Company's common stock, or 1,052,632 shares at a price of $9.50
per share. The combined sale of the Notes and common stock of the Company
generated proceeds, net of offering costs, of approximately $47.5 million that
was used to repay a portion of the then outstanding borrowings under the
Company's Credit Facility.
The Notes mature in August 2003, with no principal payments required until
maturity and quarterly interest payments payable either in cash at an annual
rate of 12% or, in limited circumstances, the issuance of additional notes at an
annual interest rate of 13% for the first three years. The Company may repay the
Notes in full without premium at any time prior to maturity. The indenture
governing the Notes contains certain covenants including, but not limited to,
limitations or restrictions on indebtedness, distributions, affiliate
transactions, liens and sale and leaseback transactions. The indenture prohibits
all dividends on the Company's stock. Warrants to purchase 1 million shares of
the Company's common stock exercisable during a period of seven years at a price
of $10.45 per share were issued in connection with the Notes.
The Notes are fully and unconditionally guaranteed, on a joint and several
basis, by each of the Company's subsidiaries (the "Subsidiary Guarantors"), all
of which are directly or indirectly wholly-owned by the Company. The obligations
of the Subsidiary Guarantors under the subsidiary guaranty agreements are
subordinated to the senior indebtedness of the Subsidiary Guarantors. The assets
of the parent, Brigham Exploration Company, consist solely of investments in its
subsidiaries.
Concurrent with the issuance of the Notes, the Company recorded a discount
on the Notes of $4.5 million to reflect the estimated value of the Warrants.
Also in connection with the issuance of the Notes, certain fees and expenses
totaling approximately $1.8 million were recorded as deferred costs. The Note
discount and deferred fees are amortized over the five year term of the Notes.
In March 1999, the indenture governing the Notes was amended to provide the
Company with the option to pay interest due on the Notes in kind, for any
reason, through the second quarter of 2000. In addition, certain financial and
other covenants were amended. The amendment also provides for a reduction in the
exercise price per share of the Warrants from $10.45 per share to $3.50 per
share.
F1-13
65
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
6. CAPITAL LEASE OBLIGATIONS
Property under capital leases consists of the following (in thousands):
DECEMBER 31,
--------------------
1998 1997
-------- --------
3-D seismic interpretation workstations and software....................... $ 620 $ 497
Office furniture and equipment............................................. 167 204
-------- --------
787 701
Accumulated depreciation and amortization.................................. (276) (241)
-------- --------
$ 511 $ 460
======== ========
The obligations under capital leases are at fixed interest rates ranging
from 8.7% to 17.9% and are collateralized by property, plant and equipment. The
future minimum lease payments under the capital leases and the present value of
the net minimum lease payments at December 31, 1998 are as follows (in
thousands):
1999............................................................................................. $ 323
2000............................................................................................. 237
2001............................................................................................. 95
2002............................................................................................. 24
------
Total minimum lease payments..................................................................... 679
Estimated executory costs included in capital leases......................................... (50)
------
Net minimum lease payments....................................................................... 629
Amounts representing interest................................................................ (90)
------
Present value of net minimum lease payments...................................................... 539
Less: current portion........................................................................... (240)
------
Noncurrent portion............................................................................... $ 299
======
7. INCOME TAXES
The provision for income taxes consists of the following (in thousands):
YEAR ENDED
DECEMBER 31,
----------------------------
1998 1997
------------ ------------
Current income taxes:
Federal...................................................................... $ -- $ --
State........................................................................ -- --
Deferred income taxes:
Federal ..................................................................... (1,186) 1,186
State........................................................................ -- --
------------ ------------
$ (1,186) $ 1,186
============ ============
The difference in income taxes provided and the amounts determined by
applying the federal statutory tax rate to income before income taxes result
from the following (in thousands):
F1-14
66
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
YEAR ENDED
DECEMBER 31,
----------------------------
1998 1997
------------ ------------
Tax at statutory rate............................................................ $ (11,740) $ 23
Add (deduct) the effect of:
January and February 1997 income, not taxable................................ -- (44)
Tax effect of Exchange....................................................... -- 1,193
Nondeductible expenses ...................................................... 10 14
Valuation reserve............................................................ 10,544 --
------------- ------------
$ (1,186) $ 1,186
============= ============
The components of deferred income tax assets and liabilities are as
follows (in thousands):
DECEMBER 31,
---------------------------
1998 1997
----------- ------------
Deferred tax assets:
Net operating loss carryforwards.............................................. $ 11,219 $ 5,563
Amortization of stock compensation............................................ 258 132
Other......................................................................... 3 3
----------- ------------
11,480 5,698
Deferred tax liability:
Depreciable and depletable property........................................... (936) (6,884)
Valuation reserve............................................................. (10,544) --
----------- ------------
$ -- $ (1,186)
=========== ============
At December 31, 1998, the Company had regular and alternative minimum tax
net operating loss carryforwards of approximately $32.9 million and $23.7
million, respectively, each including separate return limitation year carryovers
of approximately $1.2 million, which expire by December 31, 2018.
8. NET INCOME (LOSS) PER SHARE
Net income (loss) per share is presented in the consolidated financial
statements based on a basic EPS calculation as well as a diluted EPS
calculation. Basic EPS is computed by dividing net income (loss) applicable to
common shareholders by the weighted average number of common shares outstanding
during each period. Diluted EPS is computed by dividing net income (loss)
applicable to common shareholders by the weighted average number of common
shares and common share equivalents outstanding (if dilutive), during each
period. The number of common share equivalents outstanding is computed using the
treasury stock method.
Historical net loss per common share for 1996 is based on shares issued
upon consummation of the Exchange, assuming such shares has been outstanding for
all periods presented. Net loss per share for 1997 is presented giving effect to
the shares issued pursuant to the Exchange as well as shares issued in the
initial public offering. At December 31, 1997 and 1998, options and warrants to
purchase 628,737 and 1,194,654, respectively, shares of common stock were
outstanding but were not included in the computation of diluted EPS due to the
anti-dilutive effect they would have on EPS if converted.
F1-15
67
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
9. CONTINGENCIES, COMMITMENTS AND FACTORS WHICH MAY AFFECT FUTURE OPERATIONS
Litigation
The Company is, from time to time, party to certain lawsuits and claims
arising in the ordinary course of business. While the outcome of lawsuits and
claims cannot be predicted with certainty, management does not expect these
matters to have a materially adverse effect on the financial condition, results
of operations or cash flows of the Company.
As of December 31, 1998, there were no known environmental or other
regulatory matters related to the Company's operations which are reasonably
expected to result in a material liability to the Company. Compliance with
environmental laws and regulations has not had, and is not expected to have, a
material adverse effect on the Company's capital expenditures, earnings or
competitive position.
Lease Commitments
The Company leases office equipment and space under operating leases
expiring at various dates through 2002. The future minimum annual rental
payments under the noncancelable terms of these leases at December 31, 1998, are
as follows (in thousands):
1999........................................................ $ 868
2000........................................................ 790
2001........................................................ 789
2002........................................................ 395
------------
$ 2,842
============
Rental expense for the years ended December 31, 1996, 1997 and 1998 was
$253,112, $606,173 and $875,150, respectively.
Factors Which May Affect Future Operations
Since the Company's major products are commodities, significant changes
in the prices of natural gas and oil could have a significant impact on the
Company's results of operations for any particular year.
Due to an expectation for continuing difficult industry and capital markets
conditions, the Company has substantially reduced its planned capital budget for
1999 and has undertaken a number of strategic initiatives in an effort to
improve and preserve its capital liquidity in the current environment. The
Company has adapted its business strategy in the near-term through the
implementation of the following principal strategic initiatives: (i) focusing
all of the Company's planned exploration efforts in 1999 towards the drilling of
its highest grade 3-D prospects, (ii) eliminating substantially all planned
seismic and land expenditures for new projects until its capital resources can
support such additional activity, (iii) seeking to divest certain producing
natural gas and oil properties in an effort to raise capital to reduce debt
borrowings and to redirect capital to drilling projects that have the potential
to generate higher investment returns, (iv) restructuring its outstanding senior
and subordinated debt agreements to provide the Company with flexibility needed
to preserve cash flow to fund its expected near-term exploration activities, (v)
implementing an overhead
F1-16
68
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
reduction plan to reduce annual general and administrative expenses, and (vi)
evaluating opportunities to raise additional equity capital either through the
sales of interests in certain of its seismic projects or the issuance of equity
securities. The Company believes that the successful execution of these
strategic initiatives will provide it with sufficient capital resources to
execute its planned 1999 exploration program and position it to realize the
significant value it believes it has captured in its inventory of 3-D seismic
projects and delineated drilling locations. While the Company has initiated each
of these strategic directives in late 1998 and early 1999, and has effected
certain of them to date, the successful completion of any or all of these
efforts to improve the Company's capital availability within the expected time
frame is uncertain and will likely have a material impact on the Company's
near-term capital expenditure levels and growth profile.
10. SEGMENT INFORMATION
In June 1997, the FASB issued SFAS No. 131, "Disclosures about Segments of
an Enterprise and Related Information," which the Company adopted in the first
quarter of 1998. The statement supersedes SFAS No. 14, "Financial Reporting for
Segments of a Business Enterprise," replacing the "industry segment" approach
with the "management" approach. The management approach designates the internal
organization that is used by management for making operating decisions and
assessing performance as the source of the Company's reportable segments. It
also requires disclosures about products and services, geographic areas and
major customers.
All of the Company's natural gas and oil properties and related operations
are located in the United States and management has determined that the Company
has one reportable segment.
During 1998, approximately 25%, 15%, 11% and 11% of the Company's natural
gas and oil production was sold to four separate customers. During 1997,
approximately 14% and 12% of the Company's natural gas and oil production was
sold to two separate customers. During 1996, approximately 16%, 12% and 10% of
the Company's natural gas and oil production was sold to three separate
customers. However, due to the availability of other markets, the Company does
not believe that the loss of any one of these individual customers would
adversely affect the Company's result of operations.
11. FINANCIAL INSTRUMENTS
The Company periodically enters into commodity price swap agreements
which require payments to (or receipts from) counterparties based on the
differential between a fixed price and a variable price for a fixed quantity of
natural gas or crude oil without the exchange of the underlying volumes. The
notional amounts of these derivative financial instruments are based on planned
production from existing wells. The Company uses these derivative financial
instruments to manage market risks resulting from fluctuations in commodity
prices. Commodity price swaps are effective in minimizing these risks by
creating essentially equal and offsetting market exposures. The derivative
financial instruments held by the Company are not leveraged and are held for
purposes other than trading.
In 1996 and 1997, the Company was a party to a crude oil swap arrangement
resulting in a fixed price over a period of time for a specified volume of crude
oil. Adjustment to the price received for oil under these
F1-17
69
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
swap arrangements resulted in a decrease in oil revenues of $301,280 and $6,191
in 1996 and 1997, respectively.
In February 1998, the Company entered into a hedging contract whereby
10,000 MMBtu per day of natural gas is purchased and sold subject to a fixed
price swap agreement for monthly periods from April 1998 through October 1999.
Pursuant to these arrangements the Company exchanges a floating market price for
a contract month and payments are received when the fixed price exceeds the
floating price. Total natural gas subject to this hedging contract is 2,750,000
MMBtu in 1998 and 3,040,000 MMBtu in 1999. As a result of this natural gas
hedging contract, the Company realized an increase in revenues of $555,240
during 1998.
In August 1998, the Company entered into a hedging contract whereby 5,000
MMBtu per day of natural gas is purchased and sold subject to a fixed price swap
agreement for monthly periods from April 1999 through October 1999. Pursuant to
these arrangements the Company exchanges a floating market price for a fixed
contract price of $2.015 per MMBtu. Payments are made by the Company when the
floating price exceeds the fixed price for a contract month and payments are
received when the fixed price exceeds the floating price. Total natural gas
subject to this hedging contract is 1,070,000 MMBtu in 1999.
In January 1999, the Company entered into a swap agreement with terms
similar to existing agreements which relates to production for monthly periods
from November 1999 through April 2001. Pursuant to these arrangements, 15,000
MMBtu per day of natural gas is purchased and sold subject to a fixed price swap
agreement, and the Company exchanges a floating market price for a fixed
contract price of $2.065 per MMBtu. Total natural gas volumes subject to this
agreement are 915,000 MMBtu, 5,490,000 MMBtu and 1,800,000 MMBtu in 1999, 2000
and 2001, respectively.
The Company's non-derivative financial instruments include cash and cash
equivalents, accounts receivable, accounts payable and long-term debt. The
carrying amount of cash and cash equivalents, accounts receivable and accounts
payable approximate fair value because of their immediate or short maturities.
The carrying value of the Company's revolving credit facility (see Note 5)
approximates its fair market value since it bears interest at floating market
interest rates.
The Company's accounts receivable relate to natural gas and oil sales to
various industry companies, amounts due from industry participants for
expenditures made by the Company on their behalf and workstation revenues.
Credit terms, typical of industry standards, are of a short-term nature and the
Company does not require collateral. The Company's accounts receivable at
December 31, 1998 do not represent significant credit risks as they are
dispersed across many counterparties. Counterparties to the natural gas and
crude oil price swaps are investment grade financial institutions.
12. EMPLOYEE BENEFIT PLANS
Retirement Savings Plan
During 1996 the Company adopted a defined contribution 401(k) plan for
substantially all of its employees. Eligible employees may contribute up to 15%
of their compensation to this plan. The 401(k) plan provides that the Company
may, at its discretion, match employee contributions. The Company has not
matched employee contributions in any plan year.
F1-18
70
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Stock Compensation
In 1994 three employees were granted restricted interests in the Company
which vest in increments through July 1999. At the date of grant, the value of
these interests was immaterial. On February 26, 1997, in connection with the
Exchange (see Note 1), the three employees transferred these company interests
to the Company in exchange for 156,250 shares of restricted common stock of the
Company. The terms of the restricted stock and the restricted company interests
are substantially the same. The shares vest over a three-year period ending in
1999. No compensation expense will result from this exchange.
The Company adopted an incentive plan, effective upon completion of the
Exchange (see Note 1), which provides for the issuance of stock options, stock
appreciation rights, stock, restricted stock, cash or any combination of the
foregoing. The objective of this plan is to reward key employees whose
performance may have a significant effect on the success of the Company. An
aggregate of 1,588,170 shares of the Company's common stock was reserved for
issuance pursuant to this plan. The Compensation Committee of the Board of
Directors will determine the type of awards made to each participant and the
terms, conditions and limitations applicable to each award. Options granted
subsequent to March 4, 1997 have an exercise price equal to the fair market
value of the Company's common stock on the date of grant and generally vest, in
increments, over five to six years.
The Company also maintains a plan under which it offers stock compensation
to non-employee directors. Pursuant to the terms of the plan, non-employee
directors are entitled to annual grants. Options granted under this plan have an
exercise price equal to the fair value of the Company's common stock on the date
of grant and generally vest over five years.
The following table summarizes activity under the incentive plan for each
of the two years ended December 31, 1998:
WEIGHTED
AVERAGE
EXERCISE
SHARES PRICE
------------ ------------
Options outstanding December 31, 1996........................................... -- $ --
Options granted .......................................................... 646,097 5.03
Options forfeited or cancelled............................................ (17,360) 5.00
Options exercised......................................................... -- --
------------ ------------
Options outstanding December 31, 1997........................................... 628,737 5.03
Options granted........................................................... 873,500 8.62
Options forfeited or cancelled............................................ (307,583) (12.88)
Options exercised......................................................... -- --
------------ ------------
Options outstanding December 31, 1998........................................... 1,194,654 $ 5.63
============ ============
On December 14, 1998, the Board of Directors approved a proposal to cancel
and reissue outstanding employee stock options which were granted in January
1998 with an exercise price of $12.88. A total of 305,250 options with an
exercise price of $12.88 per share were cancelled and reissued with an exercise
price
F1-19
71
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
of $6.31 per share, the fair market value of the Company's stock at the date of
reissuance. Vesting schedules remained unchanged by the reissuance.
Exercise prices for options outstanding at December 31, 1997 range from
$5.00 to $14.375 and remaining contractual lives range from 5.5 years to 6
years. Exercise prices for options outstanding at December 31, 1998 range from
$5.00 to $14.375 and remaining contractual lives range from 5.5 years to 7
years. No options were exercisable at December 31, 1997 and 145,740 were
exercisable at December 31, 1998.
The weighted average fair value per share of stock compensation issued
during 1997 and 1998 was $6.24 and $5.40, respectively. The fair value for these
options was estimated using the Black-Scholes model with the following weighted
average assumptions for grants made in 1997 and 1998: risk free interest rate of
6.24% and 4.70%; volatility of the expected market prices of the Company's
common stock of 38% and 77%; expected dividend yield of zero and weighted
average expected option lives of 7.3 and 5.0 years, respectively.
The Black-Scholes valuation model was developed for use in estimating the
fair value of traded options which have no vesting restrictions and are
transferable. Additionally, the assumptions required by the valuation model are
highly subjective. Because the Company's stock options have significantly
different characteristics from those of traded options, and because changes in
the subjective input assumptions can materially affect the fair value estimate,
in management's opinion the model does not necessarily provide a reliable single
measure of the fair value of the Company's stock options.
Had compensation cost for the Company's stock options been determined based
on the fair market value at the grant dates of the awards consistent with the
methodology prescribed by SFAS No. 123 the Company's net loss and net loss per
share for 1998, 1997 and 1996 would have been the pro forma amounts indicated
below:
1998 1997
----------- -----------
Net loss:
As reported.............................................................................. $ (33,345) $ (1,117)
Pro forma ......................................................................... (33,591) (1,314)
Net loss per share:
As reported.............................................................................. (2.64) (0.10)
Pro forma................................................................................ (2.66) (0.12)
The Company granted 644,097 stock options as of March 4, 1997. These
options have an exercise price of $5.00 compared to an originally determined
estimated fair market value of the Company's common stock at date of grant of
$8.00. This grant resulted in noncash compensation expense which is being
recognized over the related vesting period of the options. During 1999, the
Company revised the fair market value of its common stock at the date these
options were granted from $8.00 to $9.00. As a result, the Company restated its
financial statements to reflect the impact of this change in estimate.
The impact of the restatement on the 1997 financial statements is presented
below:
F1-20
72
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
AS
PREVIOUSLY AS
REPORTED RESTATED
-------------- -------------
For the year ended December 31, 1997
Net loss .............................................................. $ (1,036) $ (1,117)
Net loss per share:
Basic/Diluted....................................................... (0.09) (0.10)
As of December 31, 1997
Retained earnings/(accumulated deficit)................................ 26 (55)
Total stockholders' equity......................................... 43,153 43,313
13. RELATED PARTY TRANSACTIONS
During the years ended December 31, 1996, 1997 and 1998, the Company paid
approximately $596,000, $837,000 and $851,000 respectively, in fees for land
acquisition services performed by a company owned by a brother of the Company's
President and Chief Executive Officer. Other participants in the Company's 3-D
seismic projects reimbursed the Company for a portion of these amounts.
In 1996 and 1997, the Company paid $110,000 and $18,000 for working
interests in natural gas and oil properties owned by affiliates of a member of
the Company's board of directors/management committee. The Company billed the
affiliates $68,000 in 1996 for their proportionate share of the costs related to
this project.
A Director of the Company served as a consultant to the Company on
various aspects of the Company's business and strategic issues. Fees paid for
these services by the Company were $79,200, $86,580 and $100,539 for the twelve
month periods ended December 31, 1996, 1997 and 1998, respectively. Additional
disbursements totaling approximately $13,000 and $12,000 were made during 1997
and 1998, respectively, for the reimbursement of certain expenses.
14. SUBSEQUENT EVENT
In February 1999, the Company entered into a project financing arrangement
with Duke Energy Financial Services, Inc. ("Duke") to fund the continued
exploration of five projects covered by approximately 200 square miles of 3-D
seismic data acquired in 1998. In this transaction, the Company conveyed 100% of
its working interest in land and seismic in these project areas to a newly
formed limited liability company (the "Duke LLC") for a total consideration of
$10 million. The Company is the managing member of the Duke LLC with a 1%
interest, and Duke is the sole remaining member with a 99% interest. Pursuant to
the terms of the Duke LLC agreement, the Company pays 100% of the drilling and
completion costs for all wells drilled by the Duke LLC in exchange for a 70%
working interest in the wells and their associated drilling and spacing units
and allocable seismic data. Upon 100% project payout, the Company has certain
rights to back-in for up to a 94% effective working interest in the Duke LLC
properties.
F1-21
73
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
15. NATURAL GAS AND OIL EXPLORATION AND PRODUCTION ACTIVITIES
The tables presented below provide supplemental information about natural
gas and oil exploration and production activities as defined by SFAS No. 69,
"Disclosures about Oil and Gas Producing Activities."
Results of Operations for Natural Gas and Oil Producing Activities (in
thousands)
YEAR ENDED DECEMBER 31,
----------------------------------
1998 1997 1996
---------- --------- ---------
Natural gas and oil sales............................................... $ 13,799 $ 9,184 $ 6,141
Costs and expenses:
Lease operating..................................................... 2,172 1,151 726
Production taxes.................................................... 850 549 362
Depletion of natural gas and oil properties......................... 8,410 2,743 2,323
Capitalized ceiling impairment...................................... 24,847 -- --
Income tax expense (benefit) (a).................................... (7,868) 1,318 --
---------- --------- ---------
Total costs and expenses................................................ 28,411 5,761 3,411
---------- --------- ---------
$ (14,612) $ 3,423 $ 2,730
========== ========= =========
Depletion per physical unit of production (equivalent Mcf of gas)....... $ 1.27 $ 0.88 $ 1.13
========== ========= =========
- ------------
(a) The income tax expense (benefit) for 1997 and 1998 is calculated at
the statutory rate and determined without regard to the Company's
deduction for general and administrative expenses, interest costs and
other income tax deductions and credits.
Natural gas and oil sales reflect the market prices of net production
sold or transferred, with appropriate adjustments for royalties, net profits
interest and other contractual provisions. Lease operating expenses include
lifting costs incurred to operate and maintain productive wells and related
equipment, including such costs as operating labor, repairs and maintenance,
materials, supplies and fuel consumed. Production taxes include production and
severance taxes. No provision was made for income taxes for 1996 since these
taxes are the responsibility of the partners (see Note 2). Depletion of natural
gas and oil properties relates to capitalized costs incurred in acquisition,
exploration and development activities. Results of operations do not include
interest expense and general corporate amounts.
Costs Incurred and Capitalized Costs
The costs incurred in natural gas and oil acquisition, exploration and
development activities follow (in thousands):
DECEMBER 31,
---------------------------------------
1998 1997 1996
----------- ----------- -----------
Costs incurred for the year:
Exploration.................................................... $ 67,110 $ 29,516 $ 10,527
Property acquisition........................................... 16,245 26,956 6,195
Development.................................................... 10,427 2,953 1,328
Proceeds from participants..................................... (10,502) (319) (4,111)
----------- ----------- -----------
$ 83,280 $ 59,106 $ 13,939
=========== =========== ===========
F1-22
74
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Costs incurred represent amounts incurred by the Company for exploration,
property acquisition and development activities. Periodically, the Company will
receive proceeds from participants subsequent to project initiation for an
assignment of an interest in the project. These payments are represented by
"Proceeds from participants" in the table above.
Capitalized costs related to natural gas and oil acquisition, exploration
and development activities follow (in thousands):
DECEMBER 31,
----------------------------
1998 1997
------------ ------------
Cost of natural gas and oil properties at year-end:
Proved..................................................................... $ 127,491 $ 67,744
Unproved................................................................... 52,376 28,843
------------ ------------
Total capitalized costs.................................................... 179,867 96,587
Accumulated depletion...................................................... (45,550) (12,293)
------------ ------------
$ 134,317 $ 84,294
============ ============
Following is a summary of costs (in thousands) excluded from depletion at
December 31, 1998, by year incurred. At this time, the Company is unable to
predict either the timing of the inclusion of these costs and the related
natural gas and oil reserves in its depletion computation or their potential
future impact on depletion rates.
DECEMBER 31,
----------------------------------- PRIOR
1998 1997 1996 YEARS TOTAL
---------- ---------- --------- --------- ----------
Property acquisition.......................... $ 9,659 $ 13,161 $ 1,176 $ 1,278 $ 25,274
Exploration................................... 21,577 5,072 320 133 27,102
---------- ---------- --------- --------- ----------
Total......................................... $ 31,236 $ 18,233 $ 1,496 $ 1,411 $ 52,376
========== ========== ========= ========= ==========
16. NATURAL GAS AND OIL RESERVES AND RELATED FINANCIAL DATA (UNAUDITED)
Information with respect to the Company's natural gas and oil producing
activities is presented in the following tables. Reserve quantities as well as
certain information regarding future production and discounted cash flows were
determined by the Company's independent petroleum consultants and internal
petroleum reservoir engineer.
Natural Gas and Oil Reserve Data
The following tables present the Company's estimates of its proved
natural gas and oil reserves. The Company emphasizes that reserve estimates are
approximates and are expected to change as additional information becomes
available. Reservoir engineering is a subjective process of estimating
underground accumulations of natural gas and oil 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.
Accordingly, there can be no assurance that the reserves set forth herein will
ultimately be produced nor can there be assurance that the proved undeveloped
reserves will be developed within the periods anticipated. A substantial portion
of the reserve balances were estimated utilizing the volumetric method, as
opposed to the production performance method.
F1-23
75
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
NATURAL
GAS OIL
(MMCF) (MBBLS)
------------ ------------
Proved reserves at December 31, 1995........................................... 4,257 1,672
Revisions to previous estimates............................................ (1,005) (232)
Extensions, discoveries and other additions................................ 7,742 996
Purchase of minerals-in-place.............................................. 260 3
Sales of minerals-in-place................................................. (299) (272)
Production................................................................. (698) (227)
------------ ------------
Proved reserves at December 31, 1996........................................... 10,257 1,940
Revisions to previous estimates............................................ (3,044) (447)
Extensions, discoveries and other additions................................ 33,721 735
Purchase of minerals-in-place.............................................. 13,718 1,244
Sales of minerals-in-place................................................. (40) --
Production................................................................. (1,382) (291)
------------ ------------
Proved reserves at December 31, 1997........................................... 53,230 3,181
Revisions of previous estimates............................................ (26,696) (115)
Extensions, discoveries and other additions................................ 48,050 1,752
Purchase of minerals-in-place.............................................. 851 11
Production................................................................. (4,269) (396)
------------ ------------
Proved reserves at December 31, 1998........................................... 71,166 4,433
============ ============
Proved developed reserves at December 31:
1996....................................................................... 6,034 1,453
1997....................................................................... 30,677 2,665
1998....................................................................... 38,571 2,935
Proved reserves are estimated quantities of crude natural gas and oil
which geological and engineering data indicate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are proved reserves which can be
expected to be recovered through existing wells with existing equipment and
operating methods.
Standardized Measure of Discounted Future Net Cash Inflows and Changes Therein
The following table presents a standardized measure of discounted future
net cash inflows (in thousands) relating to proved natural gas and oil reserves.
Future cash flows were computed by applying year end prices of natural gas and
oil relating to the Company's proved reserves to the estimated year-end
quantities of those reserves. Future price changes were considered only to the
extent provided by contractual agreements in existence at year-end. Future
production and development costs were computed by estimating those expenditures
expected to occur in developing and producing the proved natural gas and oil
reserves at the end of the year, based on year-end costs. Actual future cash
inflows may vary considerably and the standardized measure does not necessarily
represent the fair value of the Company's natural gas and oil reserves.
F1-24
76
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
DECEMBER 31,
---------------------------------------
1998 1997 1996
----------- ----------- -----------
Future cash inflows................................................ $ 198,082 $ 165,156 $ 84,987
Future development and production costs............................ (61,064) (40,923) (20,998)
Future income taxes................................................ (6,972) (22,919) --
----------- ----------- -----------
Future net cash inflows............................................ $ 130,046 $ 101,314 $ 63,989
=========== =========== ===========
Future net cash inflow before income taxes, discounted
at 10% per annum............................................... $ 81,741 $ 69,249 $ 44,506
=========== =========== ===========
Standardized measure of future net cash inflows discounted
at 10% per annum............................................... $ 81,649 $ 64,274 $ 44,506
=========== =========== ===========
The base sales prices for the Company's reserves were $3.71 per Mcf for
natural gas and $25.37 per Bbl for oil as of December 31, 1996, $2.27 per Mcf
for natural gas and $15.50 per Bbl for oil as of December 31, 1997, and $2.12
per Mcf for natural gas and $9.50 per Bbl for oil as of December 31, 1998. These
base prices were adjusted to reflect applicable transportation and quality
differentials on a well-by-well basis to arrive at realized sales prices used to
estimate the Company's reserves at these dates.
Changes in the future net cash inflows discounted at 10% per annum
follow:
DECEMBER 31,
---------------------------------------
1998 1997 1996
----------- ----------- -----------
Beginning of period................................................ $ 64,274 $ 44,506 $ 18,222
Sales of natural gas and oil produced, net of production
costs..................................................... (10,776) (7,484) (5,053)
Development costs incurred..................................... 5,423 1,955 246
Extensions and discoveries..................................... 52,389 38,016 29,457
Purchases of minerals-in-place................................. 687 16,965 384
Sales of minerals-in-place..................................... -- (94) (2,380)
Net change of prices and production costs...................... (11,921) (20,466) 7,023
Change in future development costs............................. (656) 319 303
Changes in production rates and other.......................... (6,109) (1,954) (342)
Revisions of quantity estimates................................ (23,470) (6,964) (5,176)
Accretion of discount.......................................... 6,925 4,450 1,822
Change in income taxes ........................................ 4,883 (4,975) --
----------- ----------- -----------
End of period...................................................... $ 81,649 $ 64,274 $ 44,506
=========== =========== ===========
F1-25
77
EXHIBIT INDEX
Number Description
- ------ -----------
2.1 -- Exchange Agreement (filed as Exhibit 2.1 to the Company's
Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
3.1 -- Certificate of Incorporation (filed as Exhibit 3.1 to the
Company's Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
3.2 -- Bylaws (filed as Exhibit 3.2 to the Company's Registration
Statement on Form S-1 (Registration No. 333-22491), and
incorporated herein by reference).
4.1 -- Form of Common Stock Certificate (filed as Exhibit 4.1 to the
Company's Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
4.2+ -- Indenture dated as of August 20, 1998 between Brigham
Exploration Company and Chase Bank of Texas, National
Association, as Trustee.
4.2.1++ -- Supplemental Indenture dated as of March 26, 1999 between
Brigham Exploration Company and Chase Bank of Texas, National
Association, as Trustee.
4.3++ -- Form of Warrant Certificate.
4.4 -- Form of Senior Subordinated Secured Note due 2003 (filed as
Exhibit 4.4 to the Company's Registration Statement on Form
S-1 (Registration No. 333-53873), and incorporated herein by
reference).
10.1 -- Agreement of Limited Partnership, dated May 1, 1992, between
Brigham Exploration Company and General Atlantic Partners III,
L.P. as general partners, and Harold D. Carter and GAP-Brigham
Partners, L.P. as limited partners (filed as Exhibit 10.1 to
the Company's Registration Statement on Form S-1 (Registration
No. 333-22491), and incorporated herein by reference).
10.1.1 -- Amendment No. 1 to Agreement of Limited Partnership of
Brigham Oil & Gas, L.P., dated May 1, 1992, by and among
Brigham Exploration Company, General Atlantic Partners III,
L.P., GAP-Brigham Partners, L.P. and Harold D. Carter (filed
as Exhibit 10.1.1 to the Company's Registration Statement on
Form S-1 (Registration No. 333-22491), and incorporated herein
by reference).
10.1.2 -- Amendment No. 2 to Agreement of Limited Partnership of
Brigham Oil & Gas, L.P., dated September 30, 1994, by and
among Brigham Exploration Company, General Atlantic Partners
III, L.P., GAP-Brigham Partners, L.P., Harold D. Carter and
the additional signatories thereto (filed as Exhibit 10.1.2 to
the Company's Registration Statement on Form S-1 (Registration
No. 333-22491), and incorporated herein by reference).
10.1.3 -- Amendment No. 3 to Agreement of Limited Partnership of
Brigham Oil & Gas, L.P., dated August 24, 1995, by and among
Brigham Exploration Company, General Atlantic Partners III,
L.P., GAP-Brigham Partners, L.P., Harold D.
78
Number Description
- ------ -----------
Carter, Craig M. Fleming, David T. Brigham and Jon L. Glass
(filed as Exhibit 10.1.3 to the Company's Registration
Statement on Form S-1 (Registration No. 333-22491), and
incorporated herein by reference).
10.1.4+ -- Amended and Restated Agreement of Limited Partnership of
Brigham Oil & Gas, L.P., dated December 30, 1997 by and among
Brigham, Inc., Brigham Holdings I, L.L.C. and Brigham Holdings
II, L.L.C.
10.2 -- Agreement of Limited Partnership of Venture Acquisitions,
L.P., dated September 23, 1994, by and between Quest
Resources, L.L.C. and RIMCO Energy, Inc. as general partners,
and RIMCO Production Company, Inc., RIMCO Exploration
Partners, L.P. I and RIMCO Exploration Partners, L.P. II, as
limited partners (filed as Exhibit 10.2 to the Company's
Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.3 -- Regulations of Quest Resources, L.L.C. (filed as Exhibit 10.3
to the Company's Registration Statement on Form S-1
(Registration No. 333-22491), and incorporated herein by
reference).
10.4 -- Management and Ownership Agreement, dated September 23, 1994,
by and among Brigham Oil & Gas, L.P., Brigham Exploration
Company, General Atlantic Partners III, L.P., Harold D.
Carter, Ben M. Brigham and GAP- Brigham Partners, L.P. (filed
as Exhibit 10.4 to the Company's Registration Statement on
Form S-1 (Registration No. 333-22491), and incorporated herein
by reference).
10.5* -- Consulting Agreement, dated May 1, 1997, by and between
Brigham Oil & Gas, L.P. and Harold D. Carter (filed as Exhibit
10.4 to the Company's Registration Statement on Form S-1
(Registration No. 33-53873), and incorporated herein by
reference).
10.6* -- Employment Agreement, by and between Brigham Exploration
Company and Ben M. Brigham (filed as Exhibit 10.7 to the
Company's Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.7* -- Form of Confidentiality and Noncompete Agreement between the
Registrant and each of its executive officers (filed as
Exhibit 10.8 to the Company's Registration Statement on Form
S-1 (Registration No. 333-22491), and incorporated herein by
reference).
10.8* -- 1997 Incentive Plan of Brigham Exploration Company (filed as
Exhibit 10.9 to the Company's Registration Statement on Form
S-1 (Registration No. 333- 22491), and incorporated herein by
reference).
10.8.1* -- Form of Option Agreement for certain executive officers (filed
as Exhibit 10.9.1 to the Company's Registration Statement on
Form S-1 (Registration No. 333- 22491), and incorporated
herein by reference).
10.8.2* -- Option Agreement dated as of March 4, 1997, by and between
Brigham Exploration Company and Jon L. Glass (filed as Exhibit
10.9.2 to the Company's Registration Statement on Form S-1
(Registration No. 333-22491), and incorporated herein by
reference).
10.9* -- Incentive Bonus Plan dated as of February 28, 1997 of Brigham,
Inc. and Brigham Oil & Gas, L.P. (filed as Exhibit 10.10 to
the Company's Registration Statement on Form S-1 (Registration
No. 333-22491), and incorporated herein by reference).
10.10 -- Two Bridgepoint Lease Agreement, dated September 30, 1996,
by and between Investors Life Insurance Company of North
America and Brigham Oil & Gas, L.P. (filed as Exhibit 10.14 to
the Company's Registration Statement on Form S- 1
(Registration No. 333-22491), and incorporated herein by
reference).
79
Number Description
- ------ -----------
10.10.1 -- First Amendment to Two Bridge Point Lease Agreement dated
April 11, 1997 between Investors Life Insurance Company of
North America and Brigham Oil & Gas, L.P. (filed as Exhibit
10.9.1 to the Company's Registration Statement on Form S-1
(Registration No. 333-53873), and incorporated herein by
reference).
10.10.2 -- Second Amendment to Two Bridge Point Lease Agreement dated
October 13, 1997 between Investors Life Insurance Company of
North America and Brigham Oil & Gas, L.P. (filed as Exhibit
10.9.2 to the Company's Registration Statement on Form S-1
(Registration No. 333-53873), and incorporated herein by
reference).
10.10.3 -- Letter dated April 17, 1998 exercising Right of First Refusal
to Lease "3rd Option Space" (filed as Exhibit 10.9.3 to the
Company's Registration Statement on Form S-1 (Registration No.
333-53873), and incorporated herein by reference).
10.11 -- Anadarko Basin Seismic Operations Agreement, dated
February 15, 1996, by and between Brigham Oil & Gas, L.P. and
Veritas Geophysical, Ltd. (filed as Exhibit 10.15 to the
Company's Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.11.1 -- Letter Amendment to Anadarko Basin Seismic Operations
Agreement, dated June 10, 1996, between Brigham Oil & Gas,
L.P. and Veritas Geophysical, Ltd. (filed as Exhibit 10.15.1
to the Company's Registration Statement on Form S-1
(Registration No. 333-22491), and incorporated herein by
reference).
10.12 -- Expense Allocation and Participation Agreement, dated April 1,
1996, between Brigham Oil & Gas, L.P. and Gasco Limited
Partnership. (filed as Exhibit 10.16 to the Company's
Registration Statement on Form S-1 (Registration No. 333-
22491), and incorporated herein by reference).
10.12.1 -- Amendment to Expense Allocation and Participation Agreement,
dated October 21, 1996, between Brigham Oil & Gas, L.P. and
Gasco Limited Partnership (filed as Exhibit 10.16.1 to the
Company's Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.13 -- Expense Allocation and Participation Agreement, dated April 1,
1996, between Brigham Oil & Gas, L.P. and Middle Bay Oil
Company, Inc. (filed as Exhibit 10.17 to the Company's
Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.13.1 -- Amendment to Expense Allocation and Participation Agreement,
dated September 26, 1996, between Brigham Oil & Gas, L.P. and
Middle Bay Oil Company, Inc. (filed as Exhibit 10.17.1 to the
Company's Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.13.2 -- Letter Amendment to Expense Allocation and Participation
Agreement, dated May 20, 1996, between Brigham Oil & Gas, L.P.
and Middle Bay Oil Company, Inc. (filed as Exhibit 10.17.2 to
the Company's Registration Statement on Form S-1 (Registration
No. 333-22491), and incorporated herein by reference).
10.14 -- Anadarko Basin Joint Participation Agreement, dated May 1,
1996, by and among Stephens Production Company and Brigham Oil
& Gas, L.P. (filed as Exhibit 10.18 to the Company's
Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.15 -- Anadarko Basin Joint Participation Agreement, dated May 1,
1996, by and between Vintage Petroleum, Inc. and Brigham Oil &
Gas, L.P. (filed as Exhibit 10.19 to the Company's
Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.16 -- Processing Alliance Agreement, dated July 20, 1993, between
Veritas Seismic Ltd. and Brigham Oil & Gas, L.P. (filed as
Exhibit 10.20 to the Company's
80
Number Description
- ------ -----------
Registration Statement on Form S-1 (Registration
No. 333-22491), and incorporated herein by reference).
10.16.1 -- Letter Amendment to Processing Alliance Agreement, dated
November 3, 1994, between Veritas Seismic Ltd. and Brigham Oil
& Gas, L.P. (filed as Exhibit 10.20.1 to the Company's
Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.17 -- Agreement and Assignment of Interest, West Bradley Project,
dated September 1, 1995, by and between Aspect Resources
Limited Liability Company and Brigham Oil & Gas, L.P. (filed
as Exhibit 10.21 to the Company's Registration Statement on
Form S-1 (Registration No. 333-22491), and incorporated herein
by reference).
10.18 -- Agreement and Assignment of Interests in lands located in
Grady County, Oklahoma, West Bradley Project, dated December
1, 1995, by and between Aspect Resources Limited Liability
Company, Brigham Oil & Gas, L.P. and Venture Acquisitions,
L.P. (filed as Exhibit 10.22 to the Company's Registration
Statement on Form S-1 (Registration No. 333-22491), and
incorporated herein by reference).
10.19 -- Agreement and Assignment of Interests, West Bradley Project,
dated December 1, 1995, by and between Aspect Resources
Limited Liability Company and Brigham Oil & Gas, L.P. (filed
as Exhibit 10.23 to the Company's Registration Statement on
Form S-1 (Registration No. 333-22491), and incorporated herein
by reference).
10.20 -- Geophysical Exploration Agreement, Hardeman Project, Hardeman
and Wilbarger Counties, Texas and Jackson County, Oklahoma,
dated March 15, 1993 by and among General Atlantic Resources,
Inc., Maynard Oil Company, Ruja Muta Corporation, Tucker
Scully Interests Ltd., JHJ Exploration, Ltd., Cheyenne
Petroleum Company, Antrim Resources, Inc., and Brigham Oil &
Gas, L.P. (filed as Exhibit 10.24 to the Company's
Registration Statement on Form S- 1 (Registration No.
333-22491), and incorporated herein by reference).
10.21 -- Agreement and Partial Assignment of Interests in OK13-P
Prospect Area, Jackson County, Oklahoma (Hardeman Project),
dated August 1, 1995, by and between Brigham Oil & Gas, L.P.
and Aspect Resources Limited Liability Company (filed as
Exhibit 10.25 to the Company's Registration Statement on Form
S-1 (Registration No. 333-22491), and incorporated herein by
reference).
10.22 -- Agreement and Partial Assignment of Interests in Q140-E
Prospect Area, Hardeman County, Texas (Hardeman Project),
dated August 1, 1995, by and between Brigham Oil & Gas, L.P.
and Aspect Resources Limited Liability Company (filed as
Exhibit 10.26 to the Company's Registration Statement on Form
S-1 (Registration No. 333-22491), and incorporated herein by
reference).
10.23 -- Agreement and Partial Assignment of Interests in Hankins #1
Chappel Prospect Agreement, Jackson County, Oklahoma (Hardeman
Project), dated March 21, 1996, by and between Brigham Oil &
Gas, L.P., NGR, Ltd. and Aspect Resources Limited Liability
Company (filed as Exhibit 10.27 to the Company's Registration
Statement on Form S-1 (Registration No. 333-22491), and
incorporated herein by reference).
10.24 -- Form of Indemnity Agreement between the Registrant and each
of its executive officers (filed as Exhibit 10.28 to the
Company's Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.25 -- Registration Rights Agreement dated February 26, 1997 by and
among Brigham Exploration Company, General Atlantic Partners
III L.P., GAP-Brigham Partners, L.P., RIMCO Partners, L.P. II,
RIMCO Partners L.P. III, and RIMCO Partners, L.P. IV, Ben M.
Brigham, Anne L. Brigham, Harold D.
81
Number Description
- ------ -----------
Carter, Craig M. Fleming, David T. Brigham and Jon L. Glass
(filed as Exhibit 10.29 to the Company's Registration
Statement on Form S-1 (Registration No. 333-22491), and
incorporated herein by reference).
10.26 -- 1997 Director Stock Option Plan (filed as Exhibit 10.30 to the
Company's Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.27 -- Form of Employee Stock Ownership Agreement (filed as Exhibit
10.31 to the Company's Registration Statement on Form S-1
(Registration No. 333-22491), and incorporated herein by
reference).
10.28 -- Agreement and Assignment of Interest in Geophysical
Exploration Agreement, Esperson Dome Project, dated November
1, 1994, by and between Brigham Oil & Gas, L.P. and Vaquero
Gas Company (filed as Exhibit 10.33 to the Company's
Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.29 -- Geophysical Exploration Agreement, Southwest Danbury Project,
Brazoria County, Texas, dated as of July 1, 1996, by and among
UNEXCO, Inc. and Brigham Oil & Gas, L.P. (filed as Exhibit
10.34 to the Company's Registration Statement on Form S-1
(Registration No. 333-22491), and incorporated herein by
reference).
10.30 -- Geophysical Exploration Agreement, Welder Project, Duval
County, Texas, dated as of October 1, 1996, by and among
UNEXCO, Inc. and Brigham Oil & Gas, L.P. (filed as Exhibit
10.35 to the Company's Registration Statement on Form S- 1
(Registration No. 333-22491), and incorporated herein by
reference).
10.31 -- Proposed Trade Structure, RIMCO/Tigre Project, Vermillion
Parish, Louisiana, among Brigham Oil & Gas, L.P., Tigre Energy
Corporation and Resource Investors Management Company (filed
as Exhibit 10.36 to the Company's Registration Statement on
Form S-1 (Registration No. 333-22491), and incorporated herein
by reference).
10.31.1 -- Letter relating to Proposed Trade Structure, RIMCO/Tigre
Project, dated January 31, 1997, from Resource Investors
Management Company to Brigham Oil & Gas, L.P. (filed as
Exhibit 10.36 to the Company's Registration Statement on Form
S- 1 (Registration No. 333-22491), and incorporated herein by
reference).
10.32 -- Anadarko Basin Seismic Operations Agreement II, dated as of
April 1, 1997, by and between Brigham Oil & Gas, L.P. (filed
as Exhibit 10.37 to the Company's Registration Statement on
Form S-1 (Registration No. 333-22491), and
incorporated herein by reference).
10.32.1 -- Letter Amendment to Anadarko Basin Seismic Operations
Agreement II, dated March 20, 1997, between Brigham Oil & Gas,
L.P. and Veritas DGC Land, Inc. (filed as Exhibit 10.37 to the
Company's Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).
10.33 -- Expense Allocation and Participation Agreement II, dated
April 1, 1997, between Brigham Oil & Gas, L.P., and Gasco
Limited Partnership (filed as Exhibit 10.31 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30,
1997, and incorporated herein by reference).
10.36 -- Credit Agreement dated as of January 26, 1998 among Brigham
Oil & Gas, L.P., Bank of Montreal, as Agent, and the lenders
signatory thereto (filed as Exhibit 10.36 to the Company's
Annual Report on Form 10-K for the year ended December 31,
1997, and incorporated herein by reference).
10.36.1+ -- First Amendment to Credit Agreement dated as of August 20,
1998 among Brigham Oil & Gas, L.P., Bank of Montreal, as
Agent, and the lenders signatory thereto.
82
Number Description
- ------ -----------
10.36.2++ -- Second Amendment to Credit Agreement dated as of March 26,
1999 among Brigham Oil & Gas, L.P., Bank of Montreal, as
Agent, and the lenders signatory thereto.
10.37 -- Guaranty Agreement dated January 26, 1998 by Brigham
Exploration Company in favor of Bank of Montreal, as Agent,
and each of the Lenders party to the Credit Agreement (filed
as Exhibit 10.33.1 to the Company's Registration Statement on
Form S-1 (Registration No. 333-53873), and incorporated herein
by reference).
10.37.1 -- First Amendment to Guaranty Agreement dated as of March 30,
1998 between Brigham Exploration Company and Bank of Montreal,
as Agent for the Lenders party to the Credit Agreement (filed
as Exhibit 10.33.2 to the Company's Registration Statement on
Form S-1 (Registration No. 333-53873), and
incorporated herein by reference).
10.37.2+ -- Second Amendment to Guaranty Agreement dated as of August 20,
1998 between Brigham Exploration Company and Bank of Montreal,
as Agent for the Lenders party to the Credit Agreement.
10.37.3++ -- Third Amendment to Guaranty Agreement dated as of March 26,
1999 between Brigham Exploration Company and Bank of Montreal,
as Agent for the Lenders party to the Credit Agreement.
10.38+ -- Securities Purchase Agreement dated as of August 20, 1998
among Brigham Exploration Company, Enron Capital & Trade
Resources Corp. and Joint Energy Development Investments II
Limited Partnership.
10.39+ -- Registration Rights Agreement dated as of August 20, 1998, by
and among Brigham Exploration Company, Enron Capital & Trade
Resources Corp. and Joint Energy Development Investments II
Limited Partnership.
10.39.1++ -- Amendment to Registration Rights Agreement dated as of
March 26, 1999, by and among Brigham Exploration Company,
Enron Capital & Trade Resources Corp., ECT Merchant
Investments Corp. and Joint Energy Development Investments II
Limited Partnership.
10.40+ -- Form of Guaranty for subsidiaries.
10.41++ -- Exchange Agreement dated as of March 30, 1999 by and between
Brigham Exploration Company and Veritas DGC Land, Inc.
10.42++ -- Registration Rights Agreement dated as of March 30, 1999 by
and between Brigham Exploration Company and Veritas DGC Land, Inc.
21+ -- Subsidiaries of the Registrant.
23.1+ -- Consent of Price Waterhouse LLP, independent public
accountants.
23.2+ -- Consent of Cawley, Gillespie & Associates, Inc., independent
petroleum engineers.
27+ -- Financial Data Schedule.
- ---------------
* Management contract or compensatory plan.
+ Filed herewith
++ Not filed herewith pursuant to Rule 12b-25 under the Act, and to be
filed by amendment.