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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, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ____________________ to ____________________
Commission file number: 000-22433
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)
---------------
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange on
Title of Each Class Which Registered
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
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 23, 2000, the Registrant had 16,712,908 shares of common stock
outstanding. 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 23, 2000, as reported on The Nasdaq Stock Market(sm), was
approximately $14 million. For purposes of determination of the foregoing
amount, only directors, executive officers and 10% or greater stockholders have
been deemed affiliates.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrant's 2000 Annual
Meeting of Stockholders to be held on May 18, 2000, 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, 1999.
TABLE OF CONTENTS
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......41
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.....................42
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE..........................42
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT..............42
ITEM 11. EXECUTIVE COMPENSATION..........................................42
ITEM 12. SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT................................42
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS............43
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
AND REPORTS ON FORM 8-K.........................................43
GLOSSARY OF OIL AND GAS TERMS.................................................52
SIGNATURES....................................................................54
INDEX TO FINANCIAL STATEMENTS...............................................F1-1
BRIGHAM EXPLORATION COMPANY
1999 ANNUAL REPORT ON FORM 10-K
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 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. Brigham's
exploration activities are concentrated primarily in three core provinces:
o the Anadarko Basin of western Oklahoma and the Texas Panhandle;
o the onshore Texas Gulf Coast; and
o 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, 1999,
Brigham has acquired 5,122 square miles (3.3 million acres) of 3-D seismic data
and has identified approximately 1,050 potential drilling locations, of which
the Company has drilled 469 through year-end 1999. The Company generates most of
its exploratory projects and, therefore, has the ability to retain a sizeable
working interest in these projects.
From inception in 1990 through 1999, Brigham drilled 395 exploratory and 74
development wells on its 3-D generated prospects with an aggregate 64%
completion rate and an average working interest of 29%. As of December 31, 1999,
the Company has added 143 Bcfe of net proved reserves to its reserve base,
approximately 121 net Bcfe of which were discovered by Brigham through its
systematic 3-D exploration drilling activities at an average net drilling cost
of $0.72 per Mcfe. In 1999, the Company's average net drilling cost was $0.37
per Mcfe and its all-in net finding and development cost was $0.52 per Mcfe,
each of which represent the lowest annual finding costs achieved by Brigham to
date.
The Company's estimated net proved reserves as of December 31, 1999 were 84
Bcfe having an aggregate Present Value of Future Net Revenues of $115 million,
compared to estimated net proved reserves as of December 31, 1996 of 22 Bcfe
having an aggregate Present Value of Future Net Revenues of $45 million. The
Company's net proved reserve volumes at December 31, 1999 are 78% natural gas
and 48% proved developed.
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 of oil and natural gas volumes.
Having acquired in excess of 5,100 square miles of 3-D seismic data in proven
producing trends, the Company's current activities are focused on generating
tangible value from its high quality inventory of 3-D delineated prospect
locations through disciplined exploration and development drilling activities
and selective non-producing asset sales.
1
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 included:
o acquiring 3-D seismic data in proven producing trends to identify and
capture potential drilling locations;
o retaining significant working interests in its exploration projects to
capture a greater share of the reserves that the Company discovers;
o identifying higher potential, higher impact prospects; and
o monetizing the value of its 3-D seismic investments by drilling its
inventory of 3-D seismic delineated locations.
During 1997 and 1998, the Company acquired 2,360 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 5,122 square miles as compared to
year-end 1996 and increased its net onshore 3-D seismic data in inventory more
than three-fold from 781 square miles at year-end 1996 to 2,507 square miles at
year-end 1998. Brigham's overall level of 3-D seismic acquisition during 1997
and 1998 was the most active in the Company's history, and the vast majority of
this newly acquired data was located in Brigham's higher potential Anadarko
Basin and Gulf Coast provinces where it has achieved historically lower average
finding costs for drilling than in its West Texas province. The majority of this
data was processed in 1998 and 1999, and the interpretation and prospect
generation is still underway. 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
drill bit at attractive finding costs over the next several years, thereby
providing opportunities for future reserve, production and cash flow growth.
Brigham's current business strategy consists of the following key elements:
o focus resources on drilling of its established 3-D delineated prospect
inventory;
o maintain a balanced risk-reward profile in its planned exploration and
development program;
o improve cash flow margins by continuing efforts to reduce per unit
finding and operating cost components; and
o selectively monetize non-producing assets to recoup capital
investments and improve project rates of return.
Focus on Drilling
From 1990 to 1999, the Company directed a significant portion of its
resources toward the establishment of a sizeable inventory of 3-D seismic
projects within proven natural gas producing trends in the Anadarko Basin and
Gulf Coast. As a result of these efforts, Brigham believes it has assembled a
significant asset base within these two core exploration provinces that it has
only begun to monetize through its drilling efforts to date. During 1999,
Brigham began to focus the majority of its resources toward drilling activities
within its established 3-D seismic projects to generate proved reserves,
production volumes and cash flow from these investments. As a result, the
Company achieved its lowest annual average drilling and finding and development
costs in its history during 1999 at $0.37 per Mcfe and $0.52 per Mcfe,
respectively. In addition, Brigham generated approximately $4 in net PV10% value
of proved reserves for every dollar invested in drilling during 1999.
2
Continuing to benefit from its existing 3-D seismic project assets,
Brigham's primary objective in 2000 is to drill the highest-grade locations
within its inventory of identified drilling locations to generate continued
growth in proved reserves and cash flow. Approximately 80% of the Company's
planned $25 million capital expenditure budget for 2000 is targeted for drilling
activities within its Anadarko Basin and Gulf Coast 3-D seismic projects.
Through December 31, 1999, the Company has achieved historical average drilling
costs of $0.56 and $0.62 per Mcfe in these two provinces, respectively. With the
significant competitive advantages afforded by the Company's sizeable
investments in 3-D seismic data within its core provinces, Brigham expects that
drilling capital expenditures should represent at least 80% of its total annual
capital expenditures for the foreseeable future.
Execute Balanced Drilling Program
The majority of the Company's historical drilling expenditures have been
directed toward exploration-oriented projects. Leveraging numerous drilling
discoveries during 1999, including the Company's potentially significant Home
Run Field discovery, Brigham's planned 2000 drilling program consists of a
balanced blend of exploration and development projects in trends where the
Company has achieved historical drilling success. Of the Company's $20 million
drilling budget planned for 2000, 54% of the expenditures relate to exploration
projects and 46% are for development drilling projects that are either currently
planned or contingent upon drilling success during the year. In addition,
approximately 20% of Brigham's planned 2000 drilling program is directed toward
continuing drilling activities in and adjacent to its Home Run Field discovery
in its Diablo Project in South Texas, in which the Company maintains a 34%
working interest. This planned activity consists of the drilling of three proved
undeveloped locations within the Home Run Field and two exploratory tests of
potentially significant Lower Vicksburg structures located in fault blocks that
are adjacent to the Company's Home Run Field discovery. Drilling success from
either of these two exploratory prospects would likely establish further
development drilling locations, thereby further enhancing the overall economics
from this project area.
Improve Operating Margins
Brigham seeks to improve its return on invested capital by achieving low
finding and development costs and by reducing and controlling its per unit
operating costs. The Company has achieved average drilling costs of $0.72 per
Mcfe during the past five years. By focusing its drilling program within areas
where the Company had previously experienced drilling success, Brigham achieved
improved returns on its drilling investments during 1999 with average drilling
costs of $0.37 per Mcfe. Importantly, the Company's all-in finding and
development costs during 1999 were $0.52 per Mcfe, a substantial improvement
from its most recent five-year average finding and development costs of $1.37
per Mcfe due to:
o Brigham's considerable prior investments in 3-D seismic and land,
principally during 1997 and 1998;
o significantly lower non-drilling capital expenditures in 1999;
o improved drilling returns achieved during 1999; and
o sales of interests in certain 3-D seismic projects in 1999 which
provided reimbursements of previously incurred expenditures.
Brigham expects this trend toward convergence of its all-in finding and
development costs and drilling costs to continue during the next few years as
the Company continues to capitalize on its extensive inventory of 3-D delineated
prospects by allocating a substantial majority of its capital expenditures to
drilling within its existing 3-D seismic project areas.
3
During the past few years, Brigham's low per unit lease operating expenses
can be attributed to:
o the relatively new nature of many of the Company's producing wells;
o focused operations in three core provinces; and
o operating a greater percentage of the wells that it drills.
Brigham intends to continue to maintain low per unit operating expenses by:
o monitoring and controlling production efficiency from its existing
producing wells;
o adding new producing wells that typically cost less to operate than
more mature wells; and
o seeking to achieve operating cost efficiencies through increased
economies of scale by greater concentration of its producing assets
within its project areas.
Additionally, Brigham undertook numerous measures to reduce and control its
overhead expenses during 1999. These measures contributed to a 33% reduction in
total general and administrative expenses (including amounts capitalized) in the
fourth quarter of 1999 relative to the fourth quarter 1998, and a 43% reduction
in net general and administrative expenses per Mcfe during the same periods.
Through a continuation of overhead cost containment efforts and production
volume growth anticipated from its planned drilling program, Brigham expects to
achieve further improvements in per unit general and administrative expenses
during 2000.
Monetize Non-Producing Assets
In addition to supporting a multi-year drilling program, Brigham believes
that its substantial investments in 3-D seismic data and undeveloped acreage
provide a significant competitive advantage to attract participants to invest in
its projects, thereby recouping a portion of its initial capital investments
typically on a promoted basis. Brigham has been effective at raising capital and
attaining promoted working interests in its 3-D seismic projects throughout its
history. During 1999, the Company raised approximately $13 million through the
sales of interests in various 3-D seismic projects or individual drilling
prospects to fund a portion of its capital expenditure program. Brigham expects
to market interests in certain 3-D seismic projects or individual prospects
during 2000 to provide incremental sources of capital for reinvestment in its
drilling program and to improve its project economics.
Exploration and Operating Approach
The Company has acquired 3-D seismic data covering 5,122 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.
Brigham typically acquires 3-D seismic data in and around existing
producing fields where the Company can benefit from the imaging of producing
analogs. These 3-D defined analogs, combined with the Company's experience in
drilling 469 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.
4
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
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 the
alliance members 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.
Brigham's operations staff includes four petroleum engineers that have an
average of over thirteen years of reservoir and operations engineering
experience, most of which was gained in the Company's primary areas of activity.
The Company's engineers work closely with Brigham's explorationists and are
integrally involved in all phases of the Company's exploration process,
including preparation of pre- and post-drill reserve estimates, analysis of full
cycle risked drilling economics, well design and production management. Brigham
conducts field operations for its operated oil and natural gas properties
through third party contract personnel. In an effort to retain better control of
its project timing, operational costs and production volumes, Brigham has
significantly increased the percentage of the wells that it operates during the
past several years. Brigham operated 44% of the gross and 73% of the net wells
it participated in during 1999, as compared with 10% and 17%, respectively, of
its wells drilled during 1996. As a result of its increased operational control
in recent years, Brigham-operated wells constituted 61% of the PV10% value of
its proved developed producing reserves at year-end 1999, as compared with only
8% at year-end 1996.
Technical Staff
The Company's experienced technical staff includes seven geophysicists,
seven geologists, four petroleum engineers, five computer applications
specialists, four geophysical/geological/engineering technicians, three landmen
and three lease and division order analysts. Brigham's 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 245 years of exploration
experience, or an average of almost 18 years per person, and more than 80 years
of 3-D CAEX workstation experience, most of which was acquired at Brigham and
various major and large independent oil companies. Brigham's team of technical
specialists was assembled according to the expertise that these individuals have
within producing basins where Brigham focuses its exploration and development
activities. By integrating both geologic and geophysical expertise within its
project teams, Brigham believes it possesses a competitive advantage in its
exploration approach. Occasionally, the Company complements and leverages its
exploration staff by seeking out alliances or retainer relationships with
geologists and other technical professionals who have extensive experience in a
particular area of interest.
5
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, to 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.
Brigham has invested extensively in the advanced computer hardware and
software necessary for 3-D seismic exploration. The Company has both Landmark
and Schlumberger 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, Seis3DV, Seis2D, BaseMap+,
GeoViz, Voxels, SynView, Seisan, SeisTie, CSA (Computed Seismic Attributes),
Surface Slice, Hampson Russell AVO Analysis and Modeling, ZEH Graphics Plotex,
CGMage Builder (graphics montage tool), and Neuralog Inc. NDS/Log and
NeuraSection.
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 Oil And Gas Markets Affects Us; Oil And Natural Gas Prices Are
Volatile" and "-- Risk Factors -- The Marketability Of Our Production Is
Dependent On Facilities That We Typically Do Not Own Or Control." For the year
ended December 31, 1999, sales to Highland Energy Company, Lantern Petroleum
Corporation and Duke Energy Field Services, Inc., were approximately 26%, 16%,
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.
6
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 Financial Condition and Results of Operations -- Risk
Factors -- We Face Significant Competition" and "-- Risk Factors -- We Have
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 and timing
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 --
Exploratory Drilling Is A Speculative Activity Involving Numerous Risks And
Uncertain Costs; We Are Dependent 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 that
unsuccessful drilling efforts will not have a material adverse effect on the
Company's business, financial condition or results of operations.
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 23, 2000, the Company had 51 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.
7
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. As part of its
efforts to reduce corporate overhead expenses, the Company agreed to sublease
approximately 5,300 square feet of excess office space at its principal
executive offices to a third party for a two-year term beginning in November
1999. In addition to its corporate headquarters location, 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, the
Company is unable to predict the future cost or impact of complying with such
laws and regulations because they are frequently amended, interpreted and
reinterpreted.
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 oil and natural gas.
These states also have statutes or regulations addressing conservation matters,
including provisions for the unitization or pooling of oil and natural gas
properties, the establishment of maximum rates of production from wells and the
regulation of spacing, plugging and abandonment of such wells.
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
landowners 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.
8
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 little control. See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Other Matters" and
"-- Risk Factors -- We Are Subject To Various Governmental Regulations And
Environmental Risks."
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 Texas
Gulf Coast; and West Texas. During the past three years, Brigham has
concentrated the majority of its 3-D seismic and drilling activities on natural
gas projects in its Anadarko Basin and Gulf Coast provinces primarily due to the
higher expected rates of return provided by these opportunities relative to its
more mature West Texas oil projects.
In 1997 and 1998, Brigham made significant investments in the acquisition
of 3-D seismic and prospective acreage in its Anadarko Basin and Gulf Coast
provinces. 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, 1999, the Company estimates that it has identified approximately
580 potential undrilled locations within its three core exploration provinces.
From inception in 1990 through 1999, Brigham achieved net drilling costs of
$0.72 per Mcfe added through its 3-D seismic exploration efforts. In addition,
over 400 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 average net drilling costs of $0.56 and $0.62 per
Mcfe, respectively.
9
Continuing its strategy implemented during 1999, Brigham intends to focus
substantially all of its efforts and available capital resources in 2000 to the
drilling and monetization of its highest grade prospects within its over 5,000
square mile inventory of 3-D seismic data. Employing this emphasis during 1999,
the Company achieved its lowest annual average drilling and finding and
development costs of $0.37 per Mcfe and $0.52 per Mcfe, respectively. In
addition, Brigham's average net drilling cost for proved developed reserve
additions during 1999 was $0.63 per Mcfe.
The Company's current 2000 capital expenditure budget is estimated to be
$25 million, which includes approximately $20 million to drill an estimated 30
to 40 gross wells. Brigham's planned 2000 drilling program is comprised of a
balanced blend of exploration and development drilling projects with
approximately 54% of budgeted drilling expenditures targeted for exploratory
prospects, 28% for development locations and the remaining 18% for development
locations that are contingent upon drilling success during the year. In
addition, the Company's 2000 budgeted drilling expenditures have been allocated
approximately 75% to its Gulf Coast province and 25% to its Anadarko Basin
province, concentrated within trends where the Company has experienced
exploration success historically. See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources."
The Company's actual capital expenditures in 2000 may differ from the
estimates discussed herein based upon cash flow and capital availability during
the year. There can be no assurance that any potential drilling locations
identified by the Company 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:
o the results of exploration and development efforts and the continuing
review and analysis of the seismic data;
o the availability of sufficient capital resources by the Company and
other participants for drilling prospects;
o 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;
o the financial resources and results of the Company; and
o the availability of leases on reasonable terms and permitting for the
potential drilling location.
In addition, there can be no assurance that the budgeted wells will, if
drilled, encounter reservoirs of commercial quantities of natural gas or oil.
Gulf Coast
The onshore Texas Gulf Coast region is a high potential, multi-pay province
that lends itself to 3-D seismic exploration due to its substantial structural
and stratigraphic complexity. 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 has assembled a
digital data base including geographical, production, geophysical and geological
information that the Company evaluates on its CAEX workstations. Brigham's team
of explorationists has assembled projects in the Expanded Wilcox and Expanded
Vicksburg trends in South Texas, and the Miocene and Upper, Middle, and Lower
Frio trends of the mid-to-southern regions of the Texas Gulf Coast, each of
which are active 3-D seismic exploration trends.
10
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, 1999, the Company had acquired 1,096 square miles
(701,440 acres) of 3-D seismic data in its Gulf Coast province. Through its
drilling efforts in this region from 1996 through 1999, Brigham had completed 32
wells in 44 attempts (73% completion rate) in the Gulf Coast and had found
cumulative net proved reserves of approximately 36 Bcfe at an average net
drilling cost of $0.62 per Mcfe. In its Gulf Coast drilling program in 1999, the
Company completed 7 wells in 12 attempts (58% completion rate) with an average
working interest of 22% that contributed to the addition of approximately 12 net
Bcfe of proved reserves (including revisions to previous estimates) at an
average net drilling cost of $0.66 per Mcfe during the year. As of December 31,
1999, Brigham had identified approximately 210 3-D delineated potential drilling
locations in the Gulf Coast province, of which the Company intends to drill 20
to 25 gross wells in 2000 with an estimated average working interest of
approximately 45%.
Brigham intends to focus its exploration and development drilling
activities in its Gulf Coast province in the following key project areas during
2000:
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 is
involved in a joint 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 in this project area. Brigham has retained a 34%
working interest in this joint exploration project in which the Company and its
participant currently control approximately 10,000 gross and net acres of
leasehold. 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 acquired an additional 33 square miles in 1998.
In the fourth quarter of 1999, Brigham confirmed a major Lower Vicksburg
field discovery, the Home Run Field, in its Diablo Project with the completion
of the Brigham-operated Palmer State #2 well (Brigham 34% working interest). The
Palmer State #2 encountered productive reservoirs in four Lower Vicksburg
intervals with 210 feet of potential pay. After completion of successive
operations to fracture stimulate each of these intervals during January and
February 2000, the well was successfully commingled to produce simultaneously
from all four Lower Vicksburg intervals. The Palmer State #2 began flowing to
sales as a commingled producer in late February 2000 at average net daily
production rates of 10.1 MMcf of natural gas and 650 Bbls of condensate, or
approximately 14.1 MMcfe in total. Brigham's net cost to drill, complete and
fracture stimulate the Palmer State #2 was approximately $0.24 per proved
developed producing Mcfe discovered, and the net PV10% of the proved producing
reserves attributable to the well were more than nine times the Company's net
drilling investment. Brigham's 3-D interpretative mapping indicates that the
Home Run Field reservoirs have over 500 feet of relief and cover approximately
1,100 acres with estimated potential gross reserves ranging from a minimum of 80
Bcfe to over 200 Bcfe (or 23 Bcfe to 58 Bcfe net), approximately 19 net Bcfe of
which were booked as proved reserves as of December 31, 1999. The Company and
its project participant have established a multi-well drilling plan for the
development of the Home Run Field that includes the planned drilling of a
minimum of three field delineation wells and two exploratory wells in adjacent
fault blocks during 2000.
The 1,100 acre Home Run Field is located upthrown from two large, untested
3-D delineated Vicksburg structures (Mariposa and Floyd) in adjacent fault
blocks that cover approximately 1,200 acres. Brigham currently plans to spud an
exploratory test of the estimated 1,000 acre Mariposa structure in the fourth
quarter of 2000. This 3-D delineated Vicksburg feature is located beneath the
shallower Mariposa Field which has produced in excess of 187 Bcf of natural gas
from the Frio. The estimated 200 acre Floyd feature is an apparent four-way
Lower Vicksburg closure that Brigham plans to test with an exploratory well in
the third quarter of 2000. The Company believes that its Home Run Field
discovery has significantly enhanced the prospectiveness of each of these large
structural closures.
11
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 geo-pressured
Lower Frio sands at depths ranging from 12,000 to 13,000 feet. The project area
was well suited to 3-D seismic imaging due to the significant structural
geologic complexity associated with Danbury Salt Dome that provides multiple
prospective pay intervals. Since commencement of drilling operations in early
1998, Brigham has completed three wells in three attempts in this project area.
The Company's two 1999 completions in this project, the Renn Gas Unit #1
(Brigham working interest 84%) and the Sebestia Gas Unit #1 (Brigham working
interest 56%), discovered gross proved reserves in the Frio interval estimated
at 12.4 Bcfe as of December 31, 1999, or 6.6 net Bcfe to the Company's revenue
interests. Brigham has identified several additional 3-D seismic
amplitude-supported prospects in the Upper and Lower Frio sections in its
Southwest Danbury Project, three of which are expected to be tested in its 2000
drilling program, including one that may be an offset to its most recent
discovery well in this project.
Hawkins Ranch and Millenium Projects
Brigham's Hawkins Ranch and Millenium Projects consist of 344 square miles
of contiguous non-proprietary 3-D seismic data in the prolific Miocene/Frio
trend in Matagorda County, Texas. Identified prospects in these project areas
target potential in the shallow, nonpressured Miocene and Frio sands as well as
the deeper, pressured Frio sands. Operators have been actively leasing and
drilling within this acreage during the past two years. This activity has
resulted in the completion of nine wells in twelve attempts, including the
discovery of a 3-D delineated field that is estimated to contain gross reserves
of approximately 40 Bcfe in three wells that have produced at rates in excess of
30 MMcfe of natural gas per day per well. Sustaining these high production
rates, these three wells have produced in excess of 37 Bcfe in less than
eighteen months. The Company's 2000 drilling program includes five 3-D seismic
amplitude-supported prospects in its Hawkins Ranch and Millenium Projects that
target combined gross unrisked reserve potential of 112 Bcfe. Three of these
five planned exploratory wells are expected to spud during the first half of
2000. Brigham expects to retain working interests ranging from 30% to 75% in its
wells planned for drilling in these project areas in 2000.
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 approximately 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 a significant carry on the
pre-seismic land and seismic acquisition costs of the project. The El Sauz
Project is an underexplored area that 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 the 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 2000, including a shallow Miocene
3-D seismic amplitude-supported four-way closure, an Upper Frio structural test
and a deep multi-target Miocene and amplitude-supported Middle Frio test. In
addition to these planned wells, the Company has identified nine additional
potential drilling opportunities in its continuing interpretation of the 3-D
seismic data within this project area. Brigham currently retains a 55% working
interest in its El Sauz Project.
Caliente Project
Brigham's Caliente Project consists of 350 square miles of contiguous
non-proprietary 3-D seismic data in the prolific Wilcox and Queen City trend in
Duval and Webb counties of Texas. Primary targets in this project include
shallow, non-pressured Queen City sands at depths ranging from 6,000 to 7,000
feet, and deeper, geo-pressured Expanded Upper Wilcox sands at depths ranging
from 10,000 to 18,000 feet. Brigham has identified 35 prospects within its
Caliente Project, including four prospects planned for drilling in 2000. The
first of these planned wells is expected to spud during the second quarter of
2000 and will test multiple pay objectives in a fault block located updip from a
well with pay on water. The Company estimates gross unrisked reserve potential
attributable to this Wilcox prospect of 25 Bcfe and it expects to retain a 50%
working interest in the well. During the second half of 2000, Brigham currently
plans to test an additional high potential Wilcox prospect in which it expects
retain a working interest of 37.5% to 50%. This prospect targets an analogous
fault block to a recent discovery that encountered over 300 feet of gross pay in
the target Wilcox objective. The Company estimates gross unrisked reserve
potential of 37 Bcfe related to this prospect.
12
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. Brigham's explorationists integrate this data
with their extensive expertise and knowledge base to generate 3-D projects in
the Anadarko Basin.
As of December 31, 1999, the Company had acquired 2,062 square miles (1.3
million acres) of 3-D seismic data in the Anadarko Basin. Through its drilling
efforts in this region from 1994 through 1999, Brigham had completed 83 wells in
109 attempts (76% completion rate) in the Anadarko Basin and had found
cumulative net proved reserves of 63 Bcfe at an average net drilling cost of
$0.56 per Mcfe. In its Anadarko Basin drilling program in 1999, the Company
completed 12 wells in 14 attempts (86% completion rate) with an average working
interest of 40% that contributed to the addition of 15 net Bcfe of proved
reserves (including revisions to previous estimates) at an average net drilling
cost of $0.17 per Mcfe during the year. As of December 31, 1999, the Company had
identified approximately 210 3-D delineated potential drilling locations in the
Anadarko Basin, of which the Company intends to drill 10 to 15 gross wells in
2000 with an estimated average working interest of 45%.
As part of its strategic initiatives to improve its capital resources and
liquidity during 1999, Brigham sold certain producing and non-producing oil and
natural gas properties located in its Anadarko Basin province to two separate
parties for a total of $17.1 million in June 1999. The divested properties were
located in two fields operated by third parties - the Chitwood Field in Grady
County, Oklahoma, and the Red Deer Creek Field in Roberts County, Texas.
Brigham's independent reservoir engineers estimated net proved reserve volumes
attributable to the properties as of June 1, 1999 of approximately 36 Bcfe, of
which 33% were classified as proved developed producing reserves and 59% were
natural gas. Brigham estimated net daily production volumes from the divested
properties to be approximately 2.8 MMcfe per day at the time these sales were
consummated. Net proceeds from these transactions were used by the Company to
reduce borrowings under its bank credit facility and to fund working capital
needs and capital expenditures during the second half of 1999. The effective
date of each transaction was June 30, 1999.
13
Brigham intends to focus its exploration and development drilling
activities in its Anadarko Basin province in the following key project areas
during 2000:
Arnett Project
Brigham's Arnett Project covers approximately 81,920 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 128 square miles of 3-D
seismic in the three phases of this project. 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. During 1999, Brigham completed all five
wells drilled in its Arnett Project, resulting in the discovery of 11.3 gross
Bcfe of proved developed reserves in Morrow sandstone objectives, or 5.4 Bcfe
net to the Company's interests. Capitalizing on these discoveries, the Company
plans to drill three offset Morrow locations during the first half of 2000. Each
of these Morrow prospects will test natural gas reserve targets estimated at
approximately 2 Bcf per well on a gross unrisked basis with dry hole costs
estimated to be approximately $400,000 per well.
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
sand channels in the Springer-aged Old Woman and Britt intervals. 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 has assembled acreage over a number of
potential drilling locations in these project areas and has at least one
exploratory well planned for its Huskie Project in 2000. This well was spud
during the first quarter 2000 and will test a prospect with approximately 20
Bcfe of gross unrisked reserve potential which is an extension to a prolific
Springer channel that has produced over 128 Bcfe. Success from this initial
exploratory well would likely establish several development locations. The
Company retains a 71% working interest in this exploratory well.
Wildcat and Panther Projects
The Company's Wildcat and Panther Projects consist of 47 and 99 square
miles, respectively, of continuous 3-D seismic data covering approximately
93,440 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 first half of 2000 to drill an updip location to a Hunton well that has
produced over 15 Bcfe since 1981 and was still producing in February 2000. The
Company believes successful completion of this exploratory test could prove up
an additional 55 Bcfe of remaining gross unrisked reserves in this producing
structure and set up several development locations.
Bearcat Project
Brigham's Bearcat Project consists of approximately 59 square miles of 3-D
seismic data covering approximately 37,760 acres in the prolific Carter Knox
anticline in Grady County, Oklahoma. This project targets 3-D seismic
amplitude-related shallow Pennsylvanian-aged channel sands and deep bar sands in
the Springer section. In early 2000, the Company drilled its first well in its
Bearcat Project, which was a 13,000 foot test of a potentially significant 3-D
delineated Springer bar feature with gross unrisked reserve potential of 100
Bcfe. The well encountered a significant thickness of Springer-aged sand which
confirmed Brigham's 3-D seismic interpretation of this feature. The well was
being tested in late March 2000, and a successful completion would establish
multiple offset development drilling opportunities.
14
West Texas
The Company's drilling activity in its West Texas province has been focused
in the Horseshoe Atoll, the Midland Basin and the Eastern Shelf of the Permian
Basin and in the Hardeman Basin. In response to reduced market prices for oil
and comparatively higher potential natural gas projects in its Anadarko Basin
and Gulf Coast provinces, the Company substantially reduced its 3-D seismic and
drilling activities in its West Texas during 1998 and 1999. Based on the recent
recovery in oil prices, the Company intends to undertake a comprehensive
analysis of its proved and unproved West Texas assets to evaluate opportunities
to generate value either through the drilling of identified 3-D prospects, the
sale of promoted interests in drillable 3-D prospects or the sale of all or a
portion of its proved reserves and 3-D prospect inventory.
As of December 31, 1999, Brigham had acquired 1,689 square miles (1.1
million acres) in the West Texas region. Through its drilling efforts in this
region from 1990 through 1999, Brigham had completed 185 wells in 299 attempts
(62% completion rate) in its West Texas province with an average working
interest of 23% and had found cumulative net proved reserves of 21 Bcfe at an
average net drilling cost of $1.31 per Mcfe. The Company participated in the
drilling of one well with a 35% working interest in its West Texas province
during 1999 which was unsuccessful. As of December 31, 1999, the Company had
identified approximately 165 3-D delineated potential drilling locations in its
West Texas projects. While the Company's 2000 drilling program does not
currently include any wells in its West Texas province, Brigham may participate
in the drilling of several of its highest quality West Texas prospects this year
to capitalize on high current oil prices.
Natural Gas and Oil Reserves
The Company's estimated total net proved reserves of natural gas and oil as
of December 31, 1997, 1998 and 1999 and the present values attributable to these
reserves as of those dates were as follows:
As of December 31,
-------------------------------
1997 1998 1999
---------- -------- ---------
Estimated net proved reserves:
Natural gas (MMcf) ........................ 53,230 71,166 65,457
Oil (MBbls) ............................... 3,181 4,433 3,027
Natural gas equivalent (MMcfe) ............ 72,316 97,764 83,618
Proved developed reserves as a percentage
of proved reserves ........................ 65% 57% 48%
Present Value of Future Net Revenues
(in thousands)............................. $ 69,249 $ 81,741 $ 114,466
Standardized Measure (in thousands).......... $ 64,274 $ 81,649 $ 113,546
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 $2.27
per Mcf for natural gas and $15.50 per Bbl for oil as of December 31, 1997,
$2.12 per Mcf for natural gas and $9.50 per Bbl for oil as of December 31, 1998,
and $2.35 per Mcf for natural gas and $22.75 per Bbl for oil as of December 31,
1999. 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.
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 represent 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 -- We Are Subject To Uncertainties In
Reserve Estimates And Future Net Cash Flows."
15
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,
---------------------------------------------------------
1997 1998 1999
---------------- ----------------- ------------------
Gross Net Gross Net Gross Net
------- ------- ------- -------- -------- --------
Exploratory Wells (1):
Natural gas..................... 15 6.5 30 15.6 8 3.4
Oil............................. 21 7.9 7 2.5 2 0.1
Non-productive ................. 26 9.8 17 8.0 7 2.4
-- --- -- --- -- ---
Total....................... 62 24.2 54 26.1 17 5.9
== ==== == ==== == ===
Development Wells (2):
Natural gas..................... 4 1.6 10 6.6 8 2.3
Oil............................. 5 1.6 3 1.5 1 0.5
Non-productive ................. 2 0.9 5 3.4 1 0.6
-- --- -- ---- -- ---
Total....................... 11 4.1 18 11.5 10 3.4
== === == ==== == ===
- ----------------
(1) From January 1, 2000 through March 23, 2000, the Company drilled, or
participated in the drilling of, two gross (0.19 net) exploratory wells, of
which one gross (0.17 net) was completed as a natural gas well and one
gross (0.02 net) was completed as an oil well.
(2) From January 1, 2000 through March 23, 2000, the Company drilled, or
participated in the drilling of, five gross (2.1 net) development wells, of
which one gross (1.0 net) was completed as a natural gas well, two gross
(0.03 net) were completed as oil wells and two gross (1.1 net) in the
process of drilling at March 23, 2000.
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 44% of the gross and
73% of the net wells it participated in during 1999.
16
Productive Wells and Acreage
Productive Wells
The following table sets forth the Company's ownership interest as of
December 31, 1999 in productive natural gas and oil wells in the areas
indicated.
Natural Gas Oil Total
-------------- ---------------- -----------------
Gross Net Gross Net Gross Net
------- ----- --------- ------ -------- ------
Province:
Anadarko Basin...... 88 32.1 12 3.7 100 35.8
Gulf Coast.......... 32 13.6 15 2.3 47 15.9
West Texas ......... 9 2.8 88 26.3 97 29.1
Other............... -- -- 2 0.7 2 0.7
--- ---- --- ---- --- ----
Total........... 129 48.5 117 33.0 246 81.5
=== ==== === ==== === ====
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,
1999:
Developed Undeveloped Total
---------------- -------------------- -------------------
Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- -----
Province:
Anadarko Basin................... 29,540 12,112 85,625 46,759 115,165 58,871
Gulf Coast....................... 2,626 1,237 23,249 14,762 25,875 15,999
West Texas ...................... 6,861 2,013 15,370 5,331 22,231 7,344
Other............................ 480 148 16,646 5,412 17,126 5,560
------ ------ ------- ------ ------- ------
Total........................ 39,507 15,510 140,890 72,264 180,397 87,774
====== ====== ======= ====== ======= ======
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, 2000................... 47,537 22,409
December 31, 2001................... 64,153 33,711
December 31, 2002................... 7,215 3,992
Thereafter.......................... 21,985 12,152
------- ------
Total........................... 140,890 72,264
======= ======
17
In addition, the Company had lease options as of December 31, 1999 to
acquire an additional 109,374 gross (67,119 net) acres, substantially all of
which expire before June 30, 2000.
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,
--------------------------
1997 1998 1999
-------- -------- --------
Production:
Natural gas (MMcf).............................. 1,382 4,269 4,197
Oil (MBbls)..................................... 291 396 346
Natural gas equivalent (MMcfe).................. 3,126 6,644 6,270
Average sales price:
Natural gas (per Mcf)........................... $ 2.56 $ 2.04 $ 2.11
Oil (per Bbl) .................................. 19.40 12.85 17.79
Average production expenses and taxes (per Mcfe) .. $ 0.55 $ 0.46 $ 0.51
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,
------------------------------------
1997 1998 1999
---------- ---------- ------------
Cost incurred for the year:
Exploration....................... $ 29,516 $ 68,214 $ 19,224
Property acquisition.............. 26,956 16,245 3,462
Development....................... 2,953 10,475 4,632
Proceeds from participants........ (319) (10,502) (29,582)
----------- ----------- ----------
$ 59,106 $ 84,432 $ (2,264)
=========== ========== ==========
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 1999.
18
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 23, 2000:
Name Age Position
- ---------------------- ----- ---------------------------------------------------
Ben M. Brigham 40 Chief Executive Officer, President and Chairman
Curtis F. Harrell 36 Chief Financial Officer and Director
David T. Brigham 39 Vice President - Land and Administration, Corporate
Secretary
A. Lance Langford 37 Vice President - Operations
Jeffery E. Larson 41 Vice President - Exploration
Karen E. Lynch 38 Vice President - Legal and General Counsel
Christopher A. Phelps 29 Vice President - Finance and Strategic Planning
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.
Curtis F. Harrell has served as Chief Financial Officer and Director of the
Company since August 1999. From 1997 to August 1999, he was Executive Vice
President and Partner at R. Chaney & Company, Inc., an equity investment firm
focused on the energy industry, where he managed the firm's investment
origination efforts in the U.S., focusing on investments in corporate equity
securities of energy companies in the exploration and production and oilfield
service industry segments. From 1995 to 1997, Mr. Harrell was a Director of
Domestic Corporate Finance for Enron Capital & Trade Resources, Inc., where he
was responsible for initiating and executing a variety of debt and equity
financing transactions for independent exploration and production companies.
Before joining Enron Capital & Trade Resources, Mr. Harrell spent eight years
working in corporate finance and reservoir engineering positions for two public
independent exploration and production companies, Kelley Oil & Gas Corporation
and Pacific Enterprises Oil Company, Inc. He has a B.S. in Petroleum Engineering
from the University of Texas at Austin and an M.B.A. from Southern Methodist
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
Jeffery E. Larson joined the Company in 1997 and has served as Vice
President -- Exploration since August 1999. Mr. Larson joined Brigham in October
1997 as Gulf Coast Exploration Manager in its Houston office where he co-managed
the Company's successful expansion into the onshore Gulf Coast province through
the initiation and assemblage of 3-D seismic projects and drilling
opportunities. In November 1998, Mr. Larson relocated to Brigham's corporate
office in Austin where he assumed an expanded role in directing the Company's
exploration activities in the Anadarko Basin, in addition to the further
advancement of its Gulf Coast activities. Prior to joining Brigham, Mr. Larson
was an explorationist in the Offshore Department of Burlington Resources, a
large independent exploration company, where he was responsible for generating
exploration and development drilling opportunities. Mr. Larson worked at
Burlington for seven years in various roles of increasing responsibility within
its exploration department. Prior to Burlington, Mr. Larson spent five years at
Exxon as a Production Geologist and Research Scientist. He has a B.S. in Earth
Science from St. Cloud State University in Minnesota and a M.S. in Geology from
the University of Montana.
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.
Christopher A. Phelps joined the Company as Manager of Finance and Investor
Relations in January 1998 and has served as Vice President -- Finance and
Strategic Planning since August 1999. Prior to joining the Company, Mr. Phelps
was a Vice President in the Investment Banking Department of Bear, Stearns & Co.
Inc., a major international securities brokerage and investment banking firm,
where he spent over five years executing a variety of capital raising and
mergers and acquisition transactions principally for independent exploration and
production companies. He holds a B.B.A. in Finance from the University of Texas
at Austin.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's 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 of the Company's common stock on Nasdaq for each quarterly
period during the past two fiscal years:
1998 1999
------------------ ------------------
High Low High Low
------ ------ ----- ------
First Quarter........... $14.00 $10.50 $6.00 $2.75
Second Quarter.......... $15.50 $8.75 $3.25 $0.88
Third Quarter........... $10.25 $5.13 $3.31 $1.94
Fourth Quarter.......... $9.50 $4.75 $2.72 $1.00
The closing market price of the Company's common stock on March 23, 2000
was $2.13 per share. As of March 23, 2000, the Company estimates that there were
82 record 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
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,
---------------------------------------------------
1995 1996 1997 1998 1999
--------- -------- ------- --------- --------
Statement of Operations Data:
Revenues:
Natural gas and oil sales............................... $ 3,578 $ 6,141 $ 9,184 $ 13,799 $ 14,992
Workstation revenue..................................... 635 627 637 390 285
-------- ------- -------- -------- --------
Total revenues..................................... 4,213 6,768 9,821 14,189 15,277
Costs and expenses:
Lease operating......................................... 761 726 1,151 2,172 2,259
Production taxes........................................ 165 362 549 850 968
General and administrative.............................. 1,897 2,199 3,570 4,672 3,481
Depletion of natural gas and oil properties............. 1,626 2,323 2,743 8,483 7,792
Depreciation and amortization........................... 533 487 306 413 525
Capitalized ceiling impairment.......................... - - - 25,926 -
Amortization of stock compensation...................... - - 388 372 1
-------- ------- -------- -------- --------
Total costs and expenses........................... 4,982 6,097 8,707 42,888 15,026
-------- ------- -------- -------- --------
Operating income (loss)................................. (769) 671 1,114 (28,699) 251
Other income (expense):
Interest expense, net................................... (936) (1,173) (1,190) (5,968) (9,697)
Interest income......................................... 128 52 145 136 176
Other expense........................................... - - - - (163)
Loss on sale of natural gas and oil properties.......... - - - - (12,195)
-------- ------- -------- -------- --------
Total other income (expense)....................... (808) (1,121) (1,045) (5,832) (21,879)
-------- ------- -------- -------- --------
Net income (loss) before income taxes................... (1,577) (450) 69 (34,531) (21,628)
Income tax benefit (expense)............................ - - (1,186) 1,186 -
-------- ------- -------- -------- --------
Net loss................................................ $ (1,577) $ (450) $ (1,117) $(33,345) $(21,628)
======== ======= ======== ======== ========
Net loss per share - basic and diluted.................. $ (0.18) $ (0.05) $ (0.10) $ (2.64) $ (1.53)
Weighted average shares outstanding - basic and diluted. 8,929 8,929 11,081 12,626 14,152
Statement of Cash Flows Data:
Net cash provided by operating activities............... $ 1,383 $ 3,710 $ 9,806 $ 14,774 $ 2,578
Net cash provided (used) by investing activities........ (8,005) (11,796) (57,300) (86,227) 1,644
Net cash provided (used) by financing activities........ 7,724 7,731 47,748 72,321 (4,049)
Other Financial Data:
Capital expenditures.................................... $ 7,935 $13,612 $ 57,170 $ 85,207 $ 25,560
As of December 31,
--------------------------------------------------
1995 1996 1997 1998 1999
--------- -------- ------- --------- --------
Balance Sheet Data:
Cash and cash equivalents............................... $ 1,802 $ 1,447 $ 1,701 $ 2,569 $ 2,742
Oil and natural gas properties, net..................... 18,538 28,005 84,294 134,317 112,066
Total assets............................................ 22,916 33,614 92,519 150,516 125,683
Long-term debt, net..................................... 16,000 24,000 32,000 94,786 97,341
Total stockholders' equity.............................. 3,694 3,244 43,313 24,681 8,998
21
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, 1999, Brigham acquired 5,122 square
miles of 3-D seismic data, identified approximately 1,050 potential drilling
locations and drilled 469 wells delineated by 3-D seismic analysis. Through its
3-D seismic-based drilling efforts, the Company had discovered an aggregate of
121 Bcfe of net proved reserves as of December 31, 1999. The Company believes
this performance demonstrates a systematic methodology for finding oil and
natural gas in onshore domestic hydrocarbon producing 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%, 66% and 81%, respectively, while its average working interest
in its wells drilled during this period was 24%, 39% and 52%, respectively. The
Company did not acquire any new 3-D seismic in 1999, and its average working
interest in its wells drilled during 1999 was 34%. 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 44% of its
gross wells and 73% of its net wells drilled in 1999 as compared with 10% of its
gross wells and 17% 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 seismic acquisition, land
and drilling, and the working interest retained by the Company. Prior to 1997,
the Company's participants typically bore 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 1997 and 1998, Brigham retained majority working interests in its
new 3-D seismic projects, and thereby reduced the financial leverage it
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 2,762 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 2,360 gross (1,727 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 these two years, the
Company acquired 1,196 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
942 square miles (40%) of 3-D seismic during 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 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.
22
As a result of lower commodity prices and reduced access to the capital
markets in late 1998 and 1999, the Company implemented a number of strategic
initiatives during 1999 to improve its capital liquidity to fund its continuing
exploration program in the difficult industry environment. These objectives and
results accomplished for each include:
o Focusing All Planned Exploration Efforts in 1999 Toward Drilling of
Highest-Grade 3-D Prospects in its Anadarko Basin and Gulf Coast Projects.
Operating under a reduced drilling budget in 1999 as compared with 1998,
Brigham directed its resources toward the drilling of identified prospects
within trends where it had achieved historical drilling success. This
focused drilling emphasis contributed to substantially improved returns on
the Company's drilling investments during 1999, with average drilling costs
of $0.37 per Mcfe and average all-in finding costs of $0.52 per Mcfe for
the year.
o Eliminating Substantially All Seismic and Land Expenditures for New
Projects. In an effort to devote the majority of its capital resources to
the drilling of its identified prospect locations, Brigham did not acquire
any new 3-D seismic data in 1999. In addition to executing the Company's
high-graded drilling program, Brigham's staff of explorationists continued
to interpret previously acquired 3-D seismic data within existing projects
to further delineate and refine pre-drill analysis of potential drilling
locations.
o Seeking to Divest Certain Producing Natural Gas and Oil Properties. In June
1999, Brigham sold interests in certain non-operated properties in two
project areas in its Anadarko Basin province for a total of $17.1 million.
These properties had estimated net proved reserves of 36 Bcfe as of June 1,
1999, of which approximately 67% were non-producing, and were producing an
estimated 2.8 net MMcfe per day at the time of the sales. After application
of the net proceeds received from these sales to the repayment of a portion
of its outstanding borrowings under its bank credit facility, Brigham was
able to increase its available borrowings under its bank credit facility by
$8 million. The increase in bank borrowing capacity resulting primarily
from these property sales was utilized to fund a substantial portion of the
Company's capital expenditures during the second half of 1999.
o Restructuring its Senior and Subordinated Debt Agreements. Working closely
with its senior and subordinated lenders in 1999 and early 2000, Brigham
was able to amend its senior credit facility and the indenture for its
subordinated notes due 2003 to provide the Company with increased borrowing
availability and financial flexibility to preserve cash flow to fund its
exploration activities. See "-- Liquidity and Capital Resources."
o Implementing an Overhead Reduction Plan. Brigham implemented several
initiatives during 1999 that were designed to reduce general and
administrative expenses and thereby increase cash flow from operations.
These cost reduction initiatives included a Company-wide salary reduction
effective in May 1999, the elimination of employee bonuses for 1999,
subleasing a portion of the Company's headquarters space effective in
November 1999, certain personnel reductions and the elimination or
reduction of various other discretionary expenses. As a result of these
actions, Brigham's total general and administrative expenses (including
amounts capitalized) were reduced 33% from the fourth quarter 1998 to the
fourth quarter 1999, while the Company's per unit net general and
administrative expenses decreased 43% from $0.92 per Mcfe to $0.52 per Mcfe
during these same periods.
o Raising Equity Capital. During 1999, Brigham raised approximately $13
million in capital through the sale of interests in non-producing assets,
primarily project and prospect equity sales to industry participants. In
addition, Brigham issued $4.2 million of common stock to Veritas DGC Land,
Inc. ("Veritas") to satisfy payment obligations due to Veritas for seismic
acquisition and processing services performed prior to 1999 and certain
seismic processing services performed during 1999. In connection with its
series of financing transactions effected in February 2000 to fund its
planned exploration and development program for 2000, Brigham raised $4.5
million through the issuance of common stock and warrants in a private
equity placement. See "--Liquidity and Capital Resources."
23
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 $25.9 million (see
Note 4 of Notes to the 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 -- Exploratory Drilling Is A
Speculative Activity Involving Numerous Risks And Uncertain Costs; We Are
Dependent On Exploratory Drilling Activities"; "-- Risk Factors -- Volatility Of
Oil And Gas Markets Affects Us; Oil And Natural Gas Prices Are Volatile"; and "
- -- Risk Factors -- We Are Subject To Uncertainties In Reserve Estimates And
Future Net Cash Flows."
In connection with the exchange of interests in the Company's predecessor
partnership with shares of the Company's common stock (the "Exchange") prior to
the Company's initial public offering 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 non-cash compensation expense over
the vesting period of the options. As a result, the Company expects to incur
unearned stock compensation amortization expenses of approximately $64,000 in
2000, $33,000 in 2001 and an aggregate of $41,000 in the two 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 diluted share) non-cash deferred
income tax charge for the year ended December 31, 1997.
24
Results of Operations
The following table sets forth certain operating data for the periods
presented.
Year Ended December 31,
------------------------------------
1997 998 1999
---------- ---------- ------------
Production:
Natural gas (MMcf)............................................. 1,382 4,269 4,197
Oil (MBbls).................................................... 291 396 346
Natural gas equivalent (MMcfe) ................................ 3,126 6,644 6,270
% Natural gas.................................................. 44% 64% 67%
Average sales prices per unit (1):
Natural gas (per Mcf).......................................... $ 2.56 $ 2.04 $ 2.11
Oil (per Bbl).................................................. 19.40 12.85 17.79
Natural gas equivalent (per Mcfe).............................. 2.94 2.08 2.39
Costs and expenses per Mcfe:
Lease operating................................................ $ 0.37 $ 0.33 $ 0.36
Production taxes............................................... 0.18 0.13 0.15
General and administrative..................................... 1.14 0.70 0.56
Depletion of natural gas and oil properties.................... 0.88 1.28 1.24
- -------------------
(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, 1999 Compared to Year Ended December 31, 1998
Natural gas and oil sales. Natural gas and oil sales increased 9% from
$13.8 million in 1998 to $15 million in 1999. An increase in the average sales
price received for natural gas and oil sales accounted for $2 million of this
increase and was offset by $797,000 from a decrease in net production volumes.
Production volumes for natural gas decreased 2% from 4,269 MMcf in 1998 to 4,197
MMcf in 1999, while the average price received for natural gas increased 3% from
$2.04 per Mcf in 1998 to $2.11 per Mcf in 1999. Production volumes for oil
decreased 13% from 396 MBbls in 1998 to 346 MBbls in 1999, while the average
price received for oil increased 38% from $12.85 per Bbl in 1998 to $17.79 per
Bbl in 1999. Natural gas and oil sales in 1999 were increased by higher realized
natural gas and oil prices and production from wells completed during 1999,
offset partially by the natural decline of existing production and from the sale
of certain producing wells in the Company's mid-1999 property divestitures. See
"-- Overview." As a result of hedging activities, natural gas revenues were
reduced by $486,000 ($0.12 per Mcf) in 1999, compared to an increase in natural
gas revenues of $555,000 ($0.13 per Mcf) in 1998. See "-- Other Matters --
Hedging Activities."
Workstation revenue. Workstation revenue decreased 27% from $390,000 in
1998 to $285,000 in 1999. Brigham recognizes workstation revenue as industry
participants in its seismic programs are charged an hourly rate for the work
performed by the Company on its 3-D seismic interpretation workstations. This
decrease in 1999 is primarily attributable to the Company's increased working
interests in its 3-D seismic projects in 1997 and 1998, which reduces the amount
of workstation interpretation costs billable to the Company's project
participants. Brigham expects workstation revenue to continue to decline in 2000
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 4% from $2.2
million ($0.33 per Mcfe) in 1998 to $2.3 million ($0.36 per Mcfe) in 1999. This
increase was primarily due to higher average working interests in its producing
wells and increased well repair and workover activity in 1999 as compared with
1998, offset in part by the elimination of lease operating expenses related to
wells sold by the Company in its mid-1999 property divestitures. See "--
Overview."
25
Production taxes. Production taxes increased 14% from $850,000 ($0.13 per
Mcfe) in 1998 to $968,000 ($0.15 per Mcfe) in 1999 primarily due to higher
average natural gas and oil sales prices and revenues. The effective average
production tax rate increased from 6.2% of natural gas and oil sales revenues in
1998 to 6.5% in 1999 resulting from changes in the geographic distribution of
the Company's producing wells.
General and administrative expenses. General and administrative expenses
decreased 25% from $4.7 million ($0.70 per Mcfe) in 1998 to $3.5 million ($0.56
per Mcfe) in 1999. This decrease was primarily attributable to a series of cost
reduction initiatives implemented by Brigham during 1999 to reduce overhead
expense levels. These initiatives included a Company-wide salary reduction
effective in May 1999, the elimination of employee bonuses for 1999, a sublease
of a portion of the Company's headquarters space effective in November 1999,
certain personnel reductions and the elimination or reduction of various other
discretionary expenses. The Company plans to continue certain of these cost
reduction initiatives in an effort to further reduce net general and
administrative expenses per unit in 2000.
Depletion of natural gas and oil properties. Depletion of natural gas and
oil properties decreased 8% from $8.5 million ($1.28 per Mcfe) in 1998 to $7.8
million ($1.24 per Mcfe) in 1999. Of this decrease, $464,000 was attributable to
the lower production volumes during the period and $227,000 was due to the
reduction in the depletion rate per unit of production. The decrease in
depletion rate per unit of production was primarily the result of the addition
of natural gas and oil reserves at lower average capital costs due to improved
average finding costs during 1999, partially offset by an increase in the
percentage of the Company's total full cost pool subject to depletion
attributable to an increase in the estimate of the evaluated portion of the
Company's natural gas and oil properties.
Interest expense. Interest expense increased from $6 million in 1998 to
$9.7 million in 1999 due to higher outstanding debt balances in 1999 at higher
effective interest rates. The Company's weighted average outstanding debt
balance increased 51% from $66 million in 1998 to $99.5 million in 1999. 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
and 1999. The effective annual interest rate on the Company's outstanding
indebtedness increased from 10.6% in 1998 to 12.6% in 1999, 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% when paid in cash and 13% when paid "in kind" through the issuance of
additional Subordinated Notes. In addition, interest expense in 1999 included
(i) $5.5 million of interest expenses related to the Subordinated Notes that was
paid in kind through the issuance of additional Subordinated Notes in lieu of
cash, and (ii) $2.3 million of non-cash charges related to the amortization of
deferred loan fees and the amortization of discount on the Subordinated Notes.
Pursuant to the recently amended terms of the Company's senior credit facility
and the Subordinated Notes, Brigham expects to pay its interest obligations
related to the Subordinated Notes through the issuance of additional
Subordinated Notes in lieu of cash during the first three quarters of 2000 (and
potentially during the fourth quarter 2000, if certain conditions are met) in an
effort to preserve cash flow to fund capital expenditures. Borrowings under the
Company's credit facility had an effective annual interest rate of 9.5% at
December 31, 1999. See "-- Liquidity and Capital Resources."
Loss on sale of natural gas and oil properties. In June 1999, the Company
sold all of its interests in certain producing and non-producing natural gas and
oil properties for a total sales price of $17.1 million. Due to the magnitude of
the reserve volumes that were attributable to these properties relative to the
Company's remaining net reserve volumes, the Company recognized a $12.2 million
non-cash loss to reflect the difference between the sales price received (after
adjustment for transaction costs) and the $28.9 million basis allocated to the
divested properties in accordance with the full-cost method of accounting for
oil and gas properties. No property divestitures occurred during 1998 for which
recognition of gain or loss was appropriate.
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 of this increase and were offset by $4.8 million 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. See "-- Overview." As a result of hedging
activities, natural gas revenues increased by $555,000 ($0.13 per Mcf) in 1998,
compared to a decrease in oil revenues of $6,200 ($0.02 per Bbl) in 1997. See
"-- Other Matters -- Hedging Activities."
26
Workstation revenue. Workstation revenue decreased 39% from $637,000 in
1997 to $390,000 in 1998. This decrease is primarily attributable to the
Company's increased working interests in its recently acquired 3-D seismic data,
which reduced the amount of workstation interpretation costs billable to the
Company's project participants.
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.
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.
Depletion of natural gas and oil properties. Depletion of natural gas and
oil properties increased 209% from $2.7 million ($0.88 per Mcfe) in 1997 to $8.5
million ($1.28 per Mcfe) in 1998. Of this increase, $4.5 million was
attributable to the increase in production volumes during the period and $1.3
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
$6 million in 1998 due to higher outstanding debt balances in 1998 at higher
effective interest rates. 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 Subordinated Notes in August 1998. 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 in kind through the issuance of additional
Subordinated Notes in lieu of cash in February 1999. Borrowings under the
Company's senior credit facility had an effective annual interest rate of 7.2%
at December 31, 1998.
27
Liquidity and Capital Resources
The Company's primary sources of capital have been credit facility and
other debt borrowings, public and private equity financings, the sale of
interests in projects and properties 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. In
January 1998, the Company entered into a new bank 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. This credit facility has been subsequently amended, including (i)
an amendment in July 1999 in connection with the Company's mid-1999 sales of
natural gas and oil properties to provide for borrowing availability of $56
million, and (ii) an amendment in February 2000 to provide for borrowing
availability of $70 million that would be increased to $75 million under certain
circumstances. 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 Company's credit
facility, thereby increasing the Company's borrowing availability under its
credit facility to fund capital expenditures. During 1999, Brigham issued $4.2
million of common stock to Veritas DGC Land, Inc., to satisfy payment
obligations due to Veritas for seismic acquisition and processing services. In
June 1999, the Company received $17.1 million ($16.7 million after transaction
costs and post-closing adjustments) from the sale of its interests in producing
and non-producing natural gas and oil properties located in two non-operated
fields in its Anadarko Basin province. In February 2000, Brigham raised $4.5
million through the issuance of common stock and warrants to purchase common
stock in a private equity placement to three institutional investors.
Credit Facility
In January 1998, the Company entered into a revolving credit agreement (the
"Credit Facility"), which provided for an initial borrowing availability of $75
million. The Credit Facility was amended in March 1999 to reduce the borrowing
availability, extend the date of borrowing base redetermination, modify certain
financial covenants, include certain additional covenants that place significant
restrictions on the Company's ability to incur certain capital expenditures, and
to increase the interest rate on outstanding borrowings.
As a result of the completion of the majority of the Company's strategic
initiatives to improve its capital resources, including the June 1999 property
divestitures and the application of the net sales proceeds to reduce borrowings
outstanding under the Credit Facility, the Company and its senior lenders
entered into an amendment to the Credit Facility in July 1999. This amendment
provided the Company with borrowing availability of $56 million principally to
fund its planned drilling activities and anticipated working capital
requirements through the end of 1999. As consideration for this amendment to the
Credit Facility, in July 1999 the Company issued to its senior lenders one
million warrants to purchase the Company's common stock at an exercise price of
$2.25 per share. The warrants have a seven-year term from the date of issuance
and are exercisable at the holders' option at any time. An estimated value of
$1.2 million was attributed to these warrants by the Company and was recognized
as additional deferred loan fees that will be amortized over the remaining
period to maturity of the Credit Facility.
In February 2000, Brigham entered into an amended and restated Credit
Facility with its existing lenders and a new lender. This amended and restated
Credit Facility provides the Company with $70 million in borrowing availability
for a three-year term, an increase from the $56 million previously available. If
Brigham exceeds certain asset value and interest coverage tests in the second or
third quarters of 2000, the total borrowing availability under the Credit
Facility will increase to $75 million. The Company's lenders have indicated that
the borrowing availability provided under the amended Credit Facility exceeded
that which would otherwise have been made available under a more traditional
conforming borrowing base calculation based on the estimated value of the
Company's current net proved reserves and its cash flow. Borrowings under the
Credit Facility in excess of $45 million are convertible into shares of Brigham
common stock in the following amounts: (i) the first $10 million of borrowings
is convertible at $3.90 per share, (ii) the second $10 million is convertible at
$6.00 per share and (iii) the final $10 million is convertible at $8.00 per
share. If the Credit Facility is repaid at maturity or is prepaid prior to
maturity without payment of cash premiums, the warrants issued to the new lender
of the Credit Facility to purchase Brigham common stock become exercisable. In
addition, certain financial covenants of the Credit Facility have been amended
or added. In connection with this most recent amendment, the Company reset the
price of the warrants previously issued to its existing senior lenders to
purchase one million shares of Brigham common stock from the then current
exercise price of $2.25 per share to $2.02 per share.
28
Principal outstanding under the Credit Facility is due at maturity on
December 31, 2002, with interest due monthly for base rate tranches or
periodically as LIBOR tranches mature. The annual interest rate for borrowings
under the Credit Facility is either the lender's base rate or LIBOR plus 3.00%,
at the Company's option. 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. At March 23, 2000, the Company had $58 million
in borrowings outstanding under the Credit Facility, which bear interest at an
annual rate of approximately 9.1%. See Note 5 of Notes to the 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
amendments to the Credit Facility in March 1999, July 1999 and February 2000, in
part, to enable the Company to comply with certain financial covenants of the
Credit Facility, including the minimum current ratio (as defined), minimum
interest coverage ratio (as defined) and the limitation on capital expenditures
related to seismic and land activities. Should the Company be unable to comply
with certain of the financial or other covenants, its senior 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. Securities issued by the Company in
connection with this financing transaction included: (i) $40 million of
Subordinated Notes, (ii) warrants to purchase one million shares of the
Company's common stock at a price of $10.45 per share (the "Subordinated Note
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 senior credit facility, which at the time
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. Interest is payable
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 the Company may pay interest in kind for a
cumulative total of seven quarterly interest payments (potentially increasing to
eight if certain conditions are met) 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 Subordinated Notes. As of March 23, 2000, the Company had made a
cumulative total of five quarterly interest payments in kind and expects to make
at least the next two quarterly interest payments (due May 2000 and August 2000)
in kind.
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,
reborrow funds utilized to prepay the Senior Indebtedness and engage in most
types of 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 provided 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 provided for a reduction in the
exercise price per share of the Subordinated Note Warrants from $10.45 per share
to $3.50 per share and extended the term of the Subordinated Note Warrants from
seven to ten years.
29
In February 2000, Brigham entered into another amendment to the terms of
the Indenture. In this amendment, the holders of the Subordinated Notes agreed
to waive the minimum consolidated interest coverage ratio covenant through June
30, 2000 and to adjust subsequent levels under this test. In addition, the
amendment provides the Company with an extension of its right to pay interest in
kind through the issuance of additional Subordinated Notes in lieu of cash
through the third quarter of 2000 and potentially through the fourth quarter of
2000 if certain conditions are met. In exchange for granting these amendments,
the Company has (i) reset the price of the Subordinated Note Warrants from a
then current exercise price of $3.50 per share to $2.43 per share, and (ii)
granted to the holders of the Subordinated Notes a term overriding royalty
interest that provides for the limited right to receive 4%, or 3% if certain
conditions are met, of the Company's net production revenue to reduce any
outstanding Subordinated Notes issued as interest paid in-kind.
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 March 1999 and
February 2000 amendments to the Indenture to enable the Company to comply with
certain financial covenants of the Indenture, including the minimum current
ratio and the minimum interest coverage ratio, as defined. 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.
At December 31, 1999 and March 23, 2000, the Company had $45.5 million and
$46.9 million, respectively, principal amount of Subordinated Notes outstanding.
Sales of Interests in Projects and Natural Gas and Oil Properties
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 Anadarko Basin 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 (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 94% 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
fund the drilling of the first six wells within these projects.
Mid-1999 Property Sales. In June 1999, Brigham sold certain producing and
non-producing natural gas and oil properties located in its Anadarko Basin
province to two separate parties for a total of $17.1 million. The divested
properties were located in two fields operated by third parties - the Chitwood
Field in Grady County, Oklahoma (originally acquired by the Company for $13.4
million in the Chitwood Acquisition in November 1997), and the Red Deer Creek
Field in Roberts County, Texas. Brigham's independent reservoir engineers
estimated net proved reserve volumes attributable to the properties as of June
1, 1999 of approximately 36 Bcfe, of which 33% were classified as proved
developed producing reserves and 59% were natural gas. The Company estimated
that net production volumes from the divested properties were 2.8 MMcfe per day
at the time of the sales. The Company used the proceeds from these transactions
to reduce borrowings under its credit facility, which contributed to provide the
Company with $8 million in borrowing availability under its then existing credit
facility that was used to fund working capital needs and capital expenditures
during the second half of 1999. The effective date of each transaction was June
30, 1999.
30
Equity Placements
Veritas Equity Issuances. On March 30, 1999, the Company entered into an
agreement with Veritas DGC Land, Inc. 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 provided 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
did not elect to pay for such services in cash. The settlement of these future
seismic processing services was determined on a quarterly basis through
September 30, 1999. Pursuant to this agreement, Brigham issued a total of
1,211,580 shares of common stock to Veritas to satisfy $4.2 million in aggregate
payment obligations due to Veritas for seismic acquisition and processing
services performed prior to 1999 and certain seismic processing services
performed during 1999.
Private Equity Placement. On February 22, 2000, Brigham entered into an
agreement to issue 2,195,122 shares of common stock and 731,707 warrants to
purchase common stock for total consideration of $4.5 million in a private
placement to a group of institutional investors led by affiliates of two members
of the Company's board of directors. The equity sale consisted of units that
include one share of common stock priced at $2.0525 per share and one-third of a
warrant to purchase Brigham common stock at an exercise price of $2.5625 per
share with a three-year term. Pricing of this private equity placement was based
on the average market price of Brigham common stock during a twenty trading day
period prior to issuance. Net proceeds from this equity placement will be used
to fund a portion of the Company's planned 2000 capital expenditures and working
capital obligations.
Cash Flow Analysis
Cash Flows from Operating Activities. Cash flows provided by operating
activities were $2.6 million in 1999, $14.8 million in 1998 and $9.8 million in
1997. The decrease in cash flows for 1999 compared to 1998 was primarily
attributable to changes in working capital (a $5 million reduction in cash flow
from working capital items in 1999 compared to an $11.9 million increase in cash
flow from working capital items in 1998). 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.
Cash Flows from Investing Activities. Cash flows provided by investing
activities in 1999 were $1.6 million as compared to cash flows used by investing
activities of $86.2 million in 1998 and $57.3 million in 1997. The increase in
net cash flow from investing activities in 1999 was due to the combined effects
of significantly reduced net capital expenditures and a total of $27.1 million
of proceeds received from the sales of natural gas and oil properties, which
consisted principally of the Company's mid-1999 producing property divestitures
and its sales of promoted interests in certain 3-D seismic projects and drilling
prospects in its Anadarko Basin and Gulf Coast regions. The decrease in cash
flow from investing activities in 1998 were the direct result of an increase in
capital expenditures related to the Company's exploration and development
activities. Capital expenditures (before the application of net proceeds
received from the sales of interests in projects) were $25.6 million in 1999,
$85.2 million in 1998 and $57.2 million in 1997.
After acquiring 1,227 gross (807 net) square miles of 3-D seismic in 1997
and 1,134 gross (920 net) square miles of 3-D seismic in 1998, the Company did
not acquire any new 3-D seismic data during 1999. The Company's drilling efforts
during the past three years resulted in the completion of 19 (6.3 net) wells in
1999, 50 (26.3 net) wells in 1998, and 45 (17.6 net) wells in 1997, which
contributed to aggregate net increases in proved reserve volumes (net of
revisions to previous estimates) of 28.7 Bcfe in 1999, 31.2 Bcfe in 1998 and
32.4 Bcfe in 1997. In addition, the Company sold interests in certain producing
and non-producing properties in 1999 for a total of $27.1 million, and it
acquired certain producing properties and related interests for $1 million in
1998 and $13.5 million in 1997.
31
Cash Flows from Financing Activities. Cash flows used by financing
activities in 1999 were $4.1 million, principally due to the net repayment of
borrowings outstanding under the Company's credit facility and the payment of
deferred loan fees. Cash flows provided by financing activities in 1998 were
$72.3 million, primarily as a result of borrowings under the Company's 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 credit facility and
proceeds from the common stock sold in the Company's initial public offering.
Capital Expenditures
Continuing its strategy implemented during 1999, Brigham intends to focus
substantially all of its efforts and available capital resources in 2000 to the
drilling and monetization of its highest grade prospects within its over 5,000
square mile inventory of 3-D seismic data. The Company's current 2000 capital
expenditure budget is estimated to be $25 million, which includes approximately
$20 million for drilling projects and $5 million for non-drilling activities
(primarily acreage acquisition and capitalized overhead costs). Brigham's
planned 2000 drilling program consists of a balanced blend of exploration and
development drilling projects with approximately 54% of budgeted drilling
expenditures targeted for exploratory prospects, 28% for development locations
and the remaining 18% for development locations that are contingent upon
drilling success during the year. In addition, the Company's 2000 budgeted
drilling expenditures have been allocated approximately 75% to its Gulf Coast
province and 25% to its Anadarko Basin province, concentrated within trends
where the Company has experienced exploration success to date. The Company
intends to fund these budgeted capital expenditures through a combination of
cash flow from operations, available borrowings under its senior credit facility
and the proceeds from its February 2000 private equity placement. Additionally,
the Company intends to supplement its available capital resources through
selective sales of interests in non-producing assets, including interests in its
3-D seismic projects and promoted interests in future drilling prospects or
locations. See "Item 2. Properties -- Primary Exploration Provinces."
Due to the Company's active exploration and development activities, Brigham
has experienced and expects to continue to experience substantial working
capital requirements. While the Company believes that cash flow from operations
and borrowings under its senior credit facility should allow the Company to
finance its planned operations through 2000 based on current conditions and
expectations, additional financing will be required in the future to fund the
Company's exploration and development activities. In the event additional
financing is not available, the Company may be required to curtail or delay its
planned activities.
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 -- Our
Hedging Transactions May Not Prevent Losses" and "Item 7A. Quantitative and
Qualitative Disclosures About Market Risk."
In 1998, Brigham 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 regional market index prices for a contract month and the
fixed contract price for the same month.
Total natural gas purchased and sold subject to swap arrangements entered
into by the Company was 2,750,000 MMBtu in 1998 and 5,025,000 MMBtu in 1999. The
Company accounted for substantially all of these transactions as hedging
activities and, accordingly, adjusted the price received for natural gas and oil
production during the period the hedged transactions occurred. Adjustments to
the price received for natural gas under these swap arrangements resulted in an
increase in natural gas revenues of $555,000 in 1998 and a decrease in natural
gas revenues of $486,000 in 1999.
32
In September 1999, Brigham sold call options on a portion of its future oil
and natural gas production. The Company applied the proceeds from the sale of
these call options to increase the effective fixed swap price on its then
existing natural gas hedging contracts during the months of October 1999 through
January 2000 by an average of $0.57 per MMBtu. For accounting purposes, the
improvement in the Company's fixed natural gas swap price attributable to these
transactions is not reflected in reported revenues. Rather, it is reflected in
(i) other income (expense) on the income statement, and (ii) amortization of
deferred loss on derivatives instruments and market value adjustment for
derivatives instruments on the cash flow statement.
The following tables summarize the Company's outstanding natural gas and
oil hedging arrangements as of March 23, 2000:
Natural Gas Hedges
2000 2001 2002
------------------------ --------------------- ---------------------
Average Average Average
Volumes Contract Volumes Contract Volumes Contract
Monthly Hedged Price Hedged Price Hedged Price
Pricing Basis Contract Term (MMBtu) ($/MMBtu) (MMBtu) ($/MMBtu) (MMBtu) ($/MMBtu)
------------- ------------- ------- --------- ------- --------- ------- ---------
Fixed Price Swaps:
Contract #1 ANR November 1999 - 2,740,000 $2.1690 600,000 $2.0650 -- --
Oklahoma April 2001
Contract #2 Houston April 2000 - 1,375,000 $2.1500 600,000 $2.1500 -- --
Ship Channel April 2001
Contract #3 TETCO April 2000 - 1,375,000 $2.0575 600,000 $2.0575 -- --
South Texas April 2001
Fixed Price Cap ANR May 2001 - -- -- 2,450,000 $2.5498 1,810,000 $2.6326
Oklahoma June 2002
Fixed Price Floor ANR May 2001 - -- -- 765,000 $1.8000 -- --
Oklahoma December 2001
Crude Oil Hedges
2000 2001 2002
---------------------- ---------------------- --------------------
Average Average Average
Volumes Contract Volumes Contract Volumes Contract
Monthly Hedged Price Hedged Price Hedged Price
Pricing Basis Contract Term (Bbls) ($/Bbl) (Bbls) ($/Bbl) (Bbls) ($/Bbl)
------------- ------------- ------ ------- ------ ------- ------ -------
Fixed Price Cap NYMEX October 1999 - 219,600 $27.40 109,200 $26.15 -- --
December 2001
Fixed Price Floor NYMEX March 2000 - 183,600 $18.00 109,200 $17.36 -- --
December 2001
33
Effects of Inflation and Changes in Prices
The Company's results of operations and cash flows are affected by changing
oil and gas prices. If the price of oil and gas 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
- -- We Are Subject To Various Governmental Regulations And Environmental Risks,"
"Item 1. Business -- Governmental Regulation" and "Item 1. Business --
Environmental Matters."
Year 2000 Issue
The Company has initially incurred no significant problems related to the
Year 2000 issue. However, the Company has not yet fully utilized all functions
and processes of its systems and accordingly cannot be sure that all its systems
will be free of Year 2000 issues. Also, the Company has no assurance that its
critical business partners, governmental agencies or other key third parties
have not incurred Year 2000 issues that may affect the Company.
Recent Accounting Pronouncements
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." The Company must adopt SFAS No. 133, as
amended by SFAS No. 137, effective January 1, 2001. 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 2000 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 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, availability of
sufficient capital resources to the Company and its project participants,
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.
34
Risk Factors
We Are Substantially Leveraged
Our outstanding long-term debt was $101.5 million (principal amount) as of
December 31, 1999. The indenture governing our senior subordinated secured notes
limits the amounts of additional debt borrowings, including borrowings under our
senior credit facility or other senior indebtedness. However, the indenture
permits us to borrow under our senior credit facility up to the lesser of $75
million or the loan commitments under the facility ($70 million as of March 23,
2000). We had $58 million of borrowings outstanding under our senior credit
facility as of March 23, 2000.
Our level of indebtedness will have several important effects on our
operations, including those listed below.
o We will dedicate a substantial portion of our cash flow from
operations to the payment of interest on our indebtedness and will not
have these cash flows available for other purposes.
o The covenants in our senior credit facility and the indenture limit
our ability to borrow additional funds or dispose of assets and may
affect our flexibility in planning for, and reacting to, changes in
business conditions.
o Our ability to obtain additional financing in the future for working
capital, capital expenditures, acquisitions, general corporate
purposes or other purposes may be impaired.
We may also be required to alter our capitalization significantly to
accommodate future exploration, development or acquisition activities. These
changes in capitalization may significantly alter our leverage and dilute the
equity interests of existing stockholders. Our ability to meet our debt service
obligations and to reduce our total indebtedness will be dependent upon our
future performance, which will be subject to general economic conditions and to
financial, business and other factors affecting our operations, many of which
are beyond our control. We cannot assure you that our future performance will
not be harmed by such economic conditions and financial, business and other
factors. See " -- Liquidity and Capital Resources."
We Have Substantial Capital Requirements
We make and will continue to make substantial capital expenditures in our
exploration and development projects. While we believe that our cash flow from
operations and borrowings under our credit facility should allow us to finance
our planned operations through 2000 based on current conditions and
expectations, additional financing will be required in the future to fund our
exploration and development activities. We cannot assure you that we will be
able to secure additional financing on reasonable terms or at all, or that
financing will continue to be available to us under our existing or new
financing arrangements. Without additional capital resources, our drilling and
other activities may be limited and our business, financial condition and
results of operations may suffer. See " -- Liquidity and Capital Resources."
Volatility Of Oil And Gas Markets Affects Us; Oil And Natural Gas Prices Are
Volatile
Our revenues, operating results and future rate of growth depend highly
upon the prices we receive for our oil and natural gas production. Historically,
the markets for oil and natural gas have been volatile and are likely to
continue to be volatile in the future. Market prices of oil and natural gas
depend on many factors beyond our control, including:
o worldwide and domestic supplies of oil and natural gas;
o the ability of the members of the Organization of Petroleum Exporting
Countries to agree to and maintain oil price and production controls;
o political instability or armed conflict in oil-producing regions;
o the price and level of foreign imports;
35
o the level of consumer demand;
o the price and availability of alternative fuels;
o the availability of pipeline capacity;
o weather conditions;
o domestic and foreign governmental regulations and taxes; and
o the overall economic environment.
We cannot predict future oil and natural gas price movements with
certainty. During 1999, the high and low prices for oil on the NYMEX were $27.07
per Bbl and $11.37 per Bbl, and the high and low prices for natural gas on the
NYMEX were $3.09 per MMBtu and $1.63 per MMBtu. Significant declines in oil and
natural gas prices for an extended period may have the following effects on our
business:
o limit our financial condition, liquidity, ability to finance planned
capital expenditures and results of operations;
o reduce the amount of oil and natural gas that we can produce
economically;
o cause us to delay or postpone some of our capital projects;
o reduce our revenues, operating income and cash flow; and
o reduce the carrying value of our oil and natural gas properties.
Our Hedging Transactions May Not Prevent Losses
In an attempt to reduce our sensitivity to energy price volatility, we use
swap and collar hedging arrangements that generally result in a fixed price or a
range of minimum and maximum price limits over a specified monthly time period.
If we do not produce our oil and natural gas reserves at rates equivalent to our
hedged position, we would be required to satisfy our obligations under hedging
contracts on potentially unfavorable terms without the ability to hedge that
risk through sales of comparable quantities of our own production. Because the
terms of our hedging contracts are based on assumptions and estimates of
numerous factors such as cost of production and pipeline and other
transportation and marketing costs to delivery points, substantial differences
between the hedged prices and actual results could harm our anticipated profit
margins and our ability to manage the risk associated with fluctuations in oil
and natural gas prices. Hedging contracts limit the benefits we will realize if
actual prices rise above the contract prices. We could be financially harmed if
the other party to the hedging contracts proves unable or unwilling to perform
its obligations under such contracts. See " -- Other Matters -- Hedging
Activities" and "Item 7A. Quantitative and Qualitative Disclosures About Market
Risk."
36
Exploratory Drilling Is A Speculative Activity Involving Numerous Risks And
Uncertain Costs; We Are Dependent On Exploratory Drilling Activities
Our revenues, operating results and future rate of growth depend highly
upon the success of our exploratory drilling program. Exploratory drilling
involves numerous risks, including the risk that we will not encounter
commercially productive natural gas or oil reservoirs. We cannot always predict
the cost of drilling, and we may be forced to limit, delay or cancel drilling
operations as a result of a variety of factors, including:
o unexpected drilling conditions;
o pressure or irregularities in formations;
o equipment failures or accidents;
o adverse weather conditions;
o compliance with governmental requirements; and
o shortages or delays in the availability of drilling rigs and the
delivery of equipment.
We may not be successful in our future drilling activities because even
with the use of 3-D seismic and other advanced technologies, exploratory
drilling is a speculative activity. We could incur losses because our use of 3-D
seismic data and other advanced technologies requires greater predrilling
expenditures than traditional drilling strategies. Even when fully utilized and
properly interpreted, our 3-D seismic data and other advanced technologies only
assist us in identifying subsurface structures and do not indicate whether
hydrocarbons are in fact present in those structures. Because we interpret the
areas desirable for drilling from 3-D seismic data gathered over large areas, we
may not acquire option and lease rights until after the seismic data is
available and, in some cases, until the drilling locations are also identified.
Although we have identified numerous potential drilling locations, we cannot
assure you that we will ever lease, drill or produce oil or natural gas oil from
these or any other potential drilling locations. We cannot assure you that we
will be successful in our drilling activities, that our overall drilling success
rate for activity within a particular province will not decline, or that our
completed wells will ultimately produce our estimated economically recoverable
reserves. Unsuccessful drilling activities could materially harm our operations
and financial condition.
We Are Subject To Various Casualty Risks
Our operations are subject to hazards and risks inherent in drilling for
and producing and transporting oil and natural gas, such as:
o fires;
o natural disasters;
o formations with abnormal pressures;
o blowouts, cratering and explosions; and
o pipeline ruptures and spills.
Any of these hazards and risks can result in the loss of hydrocarbons,
environmental pollution, personal injury claims and other damage to our
properties and the property of others. See "Item 1. Business -- Operating
Hazards and Uninsured Risks."
37
We May Not Have Enough Insurance To Cover Some Operating Risks
We maintain insurance coverage against some, but not all, potential losses
in order to protect against operating hazards. We may elect to self-insure if
our management believes that the cost of insurance, although available, is
excessive relative to the risks presented. We generally maintain insurance for
the hazards and risks inherent in drilling for and producing and transporting
oil and natural gas and believe this insurance is adequate. If an event occurs
that is not covered, or not fully covered, by insurance, it could harm our
financial condition and results of operations. In addition, we cannot fully
insure against pollution and environmental risks.
The Marketability Of Our Production Is Dependent On Facilities That We Typically
Do Not Own Or Control
The marketability of our production depends in part upon the availability,
proximity and capacity of natural gas gathering systems, pipelines and
processing facilities. We generally deliver natural gas through gas gathering
systems and gas pipelines that we do not own. Our ability to produce and market
oil and natural gas could be harmed by any dramatic change in market factors or
by:
o federal and state regulation of oil and natural gas production and
transportation;
o tax and energy policies;
o changes in supply and demand; and
o general economic conditions.
We Have Historical Operating Losses And Our Future Results May Vary; We Have
Incurred Net Losses In Each Year Of Operation
We cannot assure you that we will be profitable in the future. At December
31, 1999, we had an accumulated deficit of $55 million and total stockholders'
equity of $9 million. We have recognized the following annual net losses since
1995: $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 our
conversion from a partnership to a corporation) in 1997, $33.3 million
(including a $25.9 million non-cash writedown in the carrying value of our
natural gas and oil properties) in 1998, and $21.6 million (including a $12.2
million non-cash loss on the sale of natural gas and oil properties) in 1999.
See "Item 6. Selected Financial Data."
Our Future Operating Results May Fluctuate
Our future operating results may fluctuate significantly depending upon a
number of factors, including:
o industry conditions;
o prices of oil and natural gas;
o rates of drilling success;
o capital availability;
o rates of production from completed wells; and
o the timing and amount of capital expenditures.
This variability could cause our business, financial condition and results
of operations to suffer. In addition, any failure or delay in the realization of
expected cash flows from operating activities could limit our ability to invest
and participate in economically attractive projects.
38
Maintaining Reserves And Revenues In The Future Depends On Successful
Exploration And Development
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 we conduct successful exploration and
development activities or acquire properties containing proved reserves, or
both, our proved reserves will decline as reserves are produced. Our future oil
and natural gas production depends highly upon our ability to economically find,
develop or acquire reserves in commercial quantities.
The business of exploring for or developing reserves is capital intensive.
Reductions in our cash flow from operations and limitations on or unavailability
of external sources of capital may impair our ability to make the necessary
capital investment to maintain or expand our asset base of oil and natural gas
reserves. In addition, we cannot be certain that our future exploration and
development activities will result in additional proved reserves or that we will
be able to drill productive wells at acceptable costs. Furthermore, although
significant increases in prevailing prices for oil and natural gas could cause
increases in our revenues, our finding and development costs could also
increase. Finally, we participate in a percentage of our wells as a
non-operator. The failure of an operator of our wells to adequately perform
operations, or an operator's breach of the applicable agreements, could harm us.
We Are Subject To Uncertainties In Reserve Estimates And Future Net Cash Flows
There is substantial uncertainty in estimating quantities of proved
reserves and projecting future production rates and the timing of development
expenditures. No one can measure underground accumulations of oil and natural
gas in an exact way. Accordingly, oil and natural gas reserve engineering
requires subjective estimations of those accumulations. Estimates of other
engineers might differ widely from those of our independent petroleum engineers.
Accuracy of reserve estimates depends on the quality of available data and on
engineering and geological interpretation and judgment. Our independent
petroleum engineers may make material changes to reserve estimates based on the
results of actual drilling, testing, and production. As a result, our reserve
estimates often differ from the quantities of oil and natural gas we ultimately
recover. Also, we make certain assumptions regarding future oil and natural gas
prices, production levels, and operating and development costs that may prove
incorrect. Any significant variance from these assumptions could greatly affect
our estimates of reserves, the economically recoverable quantities of oil and
natural gas attributable to any particular group of properties, the
classifications of reserves based on risk of recovery and estimates of the
future net cash flows. See "Item 2. Properties -- Natural Gas and Oil Reserves."
Actual future net cash flows from our oil and natural gas properties also
will be affected by factors such as:
o the amount and timing of actual production;
o supply and demand for oil and natural gas;
o limits or increases in consumption by gas purchasers; and
o changes in governmental regulations or taxation.
The timing of both our production and our incurrence of expenses in
connection with the development and production of oil and natural gas properties
will affect the timing of actual future net cash flows from proved reserves, and
thus their actual present value. In addition, the 10% discount factor we use
when calculating discounted future net cash flows in compliance with the SEC
reporting requirements may not necessarily be the most appropriate discount
factor based on interest rates in effect from time to time and risks associated
with us or the oil and gas industry in general.
39
We Face Significant Competition
We operate in the highly competitive areas of oil and natural gas
exploration, exploitation, acquisition and production with other companies. We
face intense competition from a large number of independent, technology-driven
companies as well as both major and other independent oil and natural gas
companies in a number of areas such as:
o seeking to acquire desirable producing properties or new leases for
future exploration;
o marketing our oil and natural gas production; and
o seeking to acquire the equipment and expertise necessary to operate
and develop those properties.
Many of our competitors have financial and other resources substantially in
excess of those available to us. This highly competitive environment could harm
our business. See "Item 1. Business-- Competition."
We Are Subject To Various Governmental Regulations And Environmental Risks
Our 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 we believe we are
in substantial compliance with all applicable laws and regulations, legal
requirements are frequently changed and subject to interpretation, and we are
unable to predict the ultimate cost of compliance with these requirements or
their effect on our operations. We may be required to make significant
expenditures to comply with governmental laws and regulations.
Our operations are subject to complex environmental laws and regulations
adopted by federal, state and local governmental authorities. Environmental laws
and regulations change frequently, and the implementation of new, or the
modification of existing, laws or regulations could harm us. The discharge of
natural gas, oil, or other pollutants into the air, soil or water may give rise
to significant liabilities on our part to the government and third parties and
may require us to incur substantial costs of remediation. We cannot be certain
that existing environmental laws or regulations, as currently interpreted or
reinterpreted in the future, or future laws or regulations will not harm our
results of operations and financial condition. See "Item 1. Business --
Governmental Regulation; and -- Environmental Matters."
Our Business May Suffer If We Lose Key Personnel
We have assembled a team of geologists, geophysicists and engineers who
have considerable experience in applying 3-D imaging technology to explore for
and to develop oil and natural gas. We depend upon the knowledge, skills and
experience of these experts to provide 3-D imaging and to assist us in reducing
the risks associated with our participation in oil and natural gas exploration
and development projects. In addition, the success of our business depends, to a
significant extent, upon the abilities and continued efforts of our management,
particularly Ben M. Brigham, our Chief Executive Officer, President and Chairman
of the Board. We have an employment agreement with Ben M. Brigham, but do not
have an employment agreement with any of our other employees. We have key man
life insurance on Mr. Brigham in the amount of $2 million. If we lose the
services of our key management personnel or technical experts, or are unable to
attract additional qualified personnel, our business, financial condition,
results of operations, development efforts and ability to grow could suffer. We
cannot assure you that we will be successful in attracting and retaining such
executives, geophysicists, geologists and engineers. See "Item 1. Business --
Technical Staff" and "Executive Officers of the Registrant."
Control By Certain Stockholders And Certain Anti-Takeover Provisions May Affect
You; Certain Of Our Affiliates Control A Majority Of The Outstanding Common
Stock
As of March 23, 2000, our directors, executive officers and principal
stockholders, and certain of their affiliates, beneficially owned approximately
53% of our 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
our 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 makes it unlikely that any other holder
of common stock will be able to affect our management or direction. These
factors may also have the effect of delaying or preventing a change in our
management or voting control.
40
Certain Anti-Takeover Provisions May Affect Your Rights As A Stockholder
Our certificate of incorporation authorizes our Board of Directors 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 other matters described in the preceding paragraph may
discourage transactions involving actual or potential changes in our control,
including transactions that otherwise could involve payment of a premium over
prevailing market prices to holders of our common stock. We are also subject to
provisions of the Delaware General Corporation Law that may make some business
combinations more difficult.
The Market Price Of Our Stock Price Is Volatile
The trading price of our common stock and the price at which we may sell
securities in the future is subject to large fluctuations in response to any of
the following: limited trading volume in our stock, changes in government
regulations, quarterly variations in operating results, our involvement in
litigation, general market conditions, the prices of oil and natural gas,
announcements by us and our competitors, our liquidity, our ability to raise
additional funds and other events.
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 oil and natural gas hedging arrangements outstanding
at March 23, 2000, an adverse change (defined as a hypothetical 10% and 25%
increase in underlying commodity prices for open positions) would reduce cash
flow by approximately $3.3 million and $8.8 million, respectively, from
currently projected levels. Additionally, as the Company utilizes swap and
collar 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 is not reflected in
this sensitivity analysis.
41
Interest Rate Risk
The Company is subject to interest rate risk as borrowings under its senior
credit facility ($58 million outstanding as of March 23, 2000) accrue interest
at floating rates based on the lender's base rate or LIBOR. The Company does not
utilize derivative instruments to protect against changes in interest rates on
debt borrowings. See Note 9 of Notes to Consolidated Financial Statements for a
description of the Company's financial instruments at December 31, 1999.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Company's Consolidated Financial Statements and the Financial
Statements of Certain of the Company's Subsidiaries 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.
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 "2000
Proxy Statement") for its annual meeting of stockholders to be held on May 18,
2000. The 2000 Proxy Statement will be filed with the Securities and Exchange
Commission (the "Commission") not later than 120 days subsequent to December 31,
1999.
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 2000 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 1999.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item is incorporated herein by reference
to the 2000 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 1999.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
The information required by this item is incorporated herein by reference
to the 2000 Proxy Statement, which will be filed with the Commission not later
than 120 days subsequent to December 31, 1999.
42
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Consolidated Financial Statements:
See Index to Financial Statements on page F1-1.
2. Financial Statement Schedules:
See Index to Financial Statements on page F1-1.
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 (filed
as Exhibit 4.2 to the Company's Annual Report on Form 10-K for the year
ended December 31, 1998, and incorporated herein by reference).
4.2.1 Supplemental Indenture dated as of March 26, 1999 between Brigham
Exploration Company and Chase Bank of Texas, National Association, as
Trustee (filed as Exhibit 4.2.1 to the Company's Annual Report on Form
10-K for the year ended December 31, 1998, and incorporated herein by
reference).
4.3 Form of Warrant Certificate (filed as Exhibit 4.3 to the Company's
Annual Report on Form 10-K for the year ended December 31, 1998, and
incorporated herein by reference).
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).
43
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. 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. (filed as Exhibit
10.1.4 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1998, and incorporated herein by reference)
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).
10.5.1*+Letter agreement, dated as of March 20, 2000, setting forth amendments
effective January 1, 2000, to the Consulting Agreement, dated May 1,
1997, by and between Brigham Oil & Gas, L.P. and Harold D. Carter.
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).
44
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).
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).
10.10.4+Sublease agreement dated as of November 16, 1999, by and between
Brigham Oil & Gas, L.P., and ShowSupport.com, Inc.
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).
45
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 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. 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).
46
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).
10.31.2+Agreement dated March 6, 2000 by and between RIMCO Production Co.,
Tigre Energy Corporation and Brigham Oil & Gas, L.P. regarding
modifications to the Proposed Trade Structure, RIMCO/Tigre Project,
dated January 31, 1997.
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 (filed as Exhibit 10.36.1 to the Company's Annual
Report on Form 10-K for the year ended December 31, 1998, and
incorporated herein by reference).
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 (filed as Exhibit 10.36.2 to the Company's Annual
Report on Form 10-K for the year ended December 31, 1998, and
incorporated herein by reference).
47
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 (filed as Exhibit 10.37.2 to
the Company's Annual Report on Form 10-K for the year ended December 31,
1998, and incorporated herein by reference).
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 (filed as Exhibit 10.37.3 to the
Company's Annual Report on Form 10-K for the year ended December 31,
1998, and incorporated herein by reference).
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 (filed as Exhibit
10.38 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1998, and incorporated herein by reference).
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 (filed as
Exhibit 10.39 to the Company's Annual Report on Form 10-K for the year
ended December 31, 1998, and incorporated herein by reference).
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 (filed as Exhibit 10.39.1
to the Company's Annual Report on Form 10-K for the year ended December
31, 1998, and incorporated herein by reference).
10.40 Form of Guaranty for subsidiaries (filed as Exhibit 10.40 to the
Company's Annual Report on Form 10-K for the year ended December 31,
1998, and incorporated herein by reference).
10.41 Exchange Agreement dated as of March 30, 1999 by and between Brigham
Exploration Company and Veritas DGC Land, Inc. (filed as Exhibit 10.41
to the Company's Annual Report on Form 10-K for the year ended December
31, 1998, and incorporated herein by reference).
10.42 Registration Rights Agreement dated as of March 30, 1999 by and between
Brigham Exploration Company and Veritas DGC Land, Inc. (filed as Exhibit
10.42 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1998, and incorporated herein by reference).
10.43 Third Amendment to Credit Agreement dated as of July 19, 1999 among
Brigham Oil & Gas, L.P., Bank of Montreal, as Agent, and the lenders
signatory thereto (filed as Exhibit 10.1 to the Company's Quarterly
Report on Form 10-Q for the fiscal quarter ended July 31, 1999 and
incorporated by reference herein).
48
10.44 Fourth Amendment to Guaranty Agreement dated as of July 19, 1999 between
Brigham Exploration Company and Bank of Montreal, as Agent for the
lenders party to the Credit Agreement (filed as Exhibit 10.2 to the
Company's Quarterly Report on Form 10-Q for the fiscal quarter ended
July 31, 1999 and incorporated by reference herein).
10.45* Agreement dated as of August 16, 1999 between Brigham Exploration
Company and Jon L. Glass for the amendment of an Employee Stock
Ownership Agreement and Option Agreements (filed as Exhibit 10.1 to the
Company's Quarterly Report on Form 10-Q for the fiscal quarter ended
September 30, 1999 and incorporated by reference herein).
10.46* Agreement dated as of August 16, 1999 between Brigham Exploration
Company and Craig M. Fleming for the amendment of an Employee Stock
Ownership Agreement and Option Agreement (filed as Exhibit 10.2 to the
Company's Quarterly Report on Form 10-Q for the fiscal quarter ended
September 30, 1999 and incorporated by reference herein).
10.47 Form Change of Control Agreement dated as of September 20, 1999 between
Brigham Exploration Company and certain Officers (filed as Exhibit 10.3
to the Company's Quarterly Report on Form 10-Q for the fiscal quarter
ended September 30, 1999 and incorporated by reference herein).
10.48 Warrant Agreement for the Purchase of Common Stock dated as of July 19,
1999 by and between Brigham Exploration Company and Bank of Montreal
(filed as Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q
for the fiscal quarter ended September 30, 1999 and incorporated by
reference herein).
10.49 Warrant Agreement for the Purchase of Common Stock dated as of July 19,
1999 by and between Brigham Exploration Company and Societe Generale,
Southwest Agency (filed as Exhibit 10.5 to the Company's Quarterly
Report on Form 10-Q for the fiscal quarter ended September 30, 1999 and
incorporated by reference herein).
10.50 Amended and Restated Credit Agreement dated as of February 17, 2000
among Brigham Oil & Gas, L.P., as Borrower, Bank of Montreal, as Agent,
and the Lenders signatory thereto (filed as Exhibit 10.1 to the
Company's Current Report on Form 8-K filed February 29, 2000, and
incorporated herein by reference).
10.51 Amended and Restated Guaranty Agreement dated as of February 17, 2000 by
Brigham Exploration Company in favor of Bank of Montreal, as Agent, and
each of the Lenders party to the Amended and Restated Credit Agreement
(filed as Exhibit 10.2 to the Company's Current Report on Form 8-K filed
February 29, 2000 and incorporated herein by reference).
10.52 Partial Assignment of Notes dated as of February 17, 2000 by and among
(i) Bank of Montreal, (ii) Societe Generale, Southwest Agency, (iii)
Shell Capital Inc., and (iv) Brigham Oil & Gas, L.P. (filed as Exhibit
10.3 to the Company's Current Report on Form 8-K filed February 29, 2000
and incorporated herein by reference).
10.53 First Amendment to Warrant Agreement dated as of February 17, 2000
between Brigham Exploration Company and Bank of Montreal (filed as
Exhibit 10.4 to the Company's Current Report on Form 8-K filed February
29, 2000 and incorporated herein by reference).
10.54 First Amendment to Warrant Agreement dated as of February 17, 2000
between Brigham Exploration Company and Societe Generale, Southwest
Agency (filed as Exhibit 10.5 to the Company's Current Report on Form
8-K filed February 29, 2000 and incorporated herein by reference).
10.55 Equity Conversion Agreement dated as of February 17, 2000 by and among
Brigham Oil & Gas, L.P., Brigham Exploration Company and Shell Capital
Inc. and its successors and assigns (filed as Exhibit 10.6 to the
Company's Current Report on Form 8-K filed February 29, 2000 and
incorporated herein by reference).
10.56 Warrant Agreement dated as of February 17, 2000 by and between Brigham
Exploration Company and Shell Capital Inc. (filed as Exhibit 10.7 to the
Company's Current Report on Form 8-K filed February 29, 2000 and
incorporated herein by reference).
49
10.57 Registration Rights Agreement dated as of February 17, 2000 by and
between Brigham Exploration Company and Shell Capital Inc. (filed as
Exhibit 10.8 to the Company's Current Report on Form 8-K filed February
29, 2000 and incorporated herein by reference).
10.58 Letter dated as of February 17, 2000 regarding certain fees pursuant to
Credit Agreement dated as of February 17, 2000, among Brigham Oil & Gas,
L.P., Bank of Montreal, as Agent, Shell Capital Inc. and the lenders
signatory thereto (filed as Exhibit 10.9 to the Company's Current Report
on Form 8-K filed February 29, 2000 and incorporated herein by
reference).
10.59 Second Amendment to Intercreditor and Subordination Agreement dated as
of February 17, 2000 by and among ECT Merchant Investments Corp., Joint
Energy Development Investments II Limited Partnership and Bank of
Montreal, as agent for each of the lenders that is a signatory to, or
which becomes a signatory to, the Senior Credit Agreement (filed as
Exhibit 10.10 to the Company's Current Report on Form 8-K filed February
29, 2000 and incorporated herein by reference).
10.60 Second Amendment to Indenture dated as of February 17, 2000 among
Brigham Exploration Company and Chase Bank of Texas, National
Association (filed as Exhibit 10.11 to the Company's Current Report on
Form 8-K filed February 29, 2000 and incorporated herein by reference).
10.61 Conveyance of Adjustable Term Overriding Royalty Interest dated as of
February 17, 2000 by and between Brigham Oil & Gas, L.P., and ECT
Merchant Investments Corp. and Joint Energy Development Investments II
Limited Partnership (filed as Exhibit 10.12 to the Company's Current
Report on Form 8-K filed February 29, 2000 and incorporated herein by
reference).
10.62 Warrant Certificate dated as of February 17, 2000 by and between Brigham
Exploration Company and Joint Energy Development Investments II Limited
Partnership (filed as Exhibit 10.13 to the Company's Current Report on
Form 8-K filed February 29, 2000 and incorporated herein by reference).
10.63 Warrant Certificate dated as of February 17, 2000 by and between Brigham
Exploration Company and ECT Merchant Investments Corp. (filed as Exhibit
10.14 to the Company's Current Report on Form 8-K filed February 29,
2000 and incorporated herein by reference).
10.64 Securities Purchase and Registration Rights Agreement dated as of
February 22, 2000 by and among Brigham Exploration Company and GAP
Coinvestment Partners II, L.P., Special Situations Private Equity Fund,
L.P., and Aspect Resources, L.L.C. (filed as Exhibit 10.15 to the
Company's Current Report on Form 8-K filed February 29, 2000 and
incorporated herein by reference).
10.65+ Joint Development Agreement, dated as of February 10, 1999, by and
between Brigham Oil & Gas, L.P. and Aspect Resources LLC.
10.65.1+First Amendment, dated as of May 10, 1999, to that certain Joint
Development Agreement entered into effective as of February 10, 1999, by
and between Brigham Oil & Gas, L.P. and Aspect Resources LLC.
10.65.2+Acquisition and Participation Agreement, dated October 21, 1999, by and
between Brigham Oil & Gas, L.P. and Aspect Resources LLC.
10.65.3+Letter agreement, dated as of December 30, 1999, regarding amendments
to Joint Development Agreement, dated as of February 10, 1999, as
amended, by and between Brigham Oil & Gas, L.P. and Aspect Resources
LLC.
10.66+ Letter agreement dated as of September 6, 1999 between Brigham Oil &
Gas, L.P. and Brigham Land Management Company, Inc. regarding work to be
performed within Brigham's Angelton Project.
50
21+ Subsidiaries of the Registrant.
23.1+ Consent of PricewaterhouseCoopers 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.
(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.
51
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.
Completion 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.
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.
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%.
52
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%.
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.
53
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 24, 2000.
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 24, 2000, 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/ Curtis F. Harrell
- ------------------------------------------------------------
Curtis F. Harrell
Chief Financial Officer and Director
(principal financial and accounting officer)
/s/ Anne L. Brigham
- ------------------------------------------------------------
Anne L. Brigham
Director
/s/ Harold D. Carter
- ------------------------------------------------------------
Harold D. Carter
Director
/s/ Alexis M. Cranberg
- ------------------------------------------------------------
Alexis M. Cranberg
Director
/s/ Stephen P. Reynolds
- ------------------------------------------------------------
Stephen P. Reynolds
Director
54
INDEX TO FINANCIAL STATEMENTS
Page
----
Financial Statements of Brigham Exploration Company
Report of Independent Accountants.................................... F1-2
Consolidated Balance Sheets as of December 31, 1999 and 1998......... F1-3
Consolidated Statements of Operations for the Years Ended
December 31, 1999, 1998, and 1997................................. F1-4
Consolidated Statements of Stockholders' Equity for the Years Ended
December 31, 1999, 1998, and 1997................................. F1-5
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1999, 1998, and 1997................................. F1-6
Notes to the Consolidated Financial Statements....................... F1-7
Financial Statements of Certain Brigham Exploration Company Subsidiaries
Report of Independent Accountants.................................... F2-1
Balance Sheets as of December 31, 1999............................... F2-2
Balance Sheets as of December 31, 1998............................... F2-3
Statements of Operations for the Year Ended December 31, 1999........ F2-4
Statements of Operations for the Year Ended December 31, 1998........ F2-5
Statements of Operations for the Year Ended December 31, 1997........ F2-6
Statements of Equity for the Year Ended December 31, 1999............ F2-7
Statements of Equity for the Year Ended December 31, 1998............ F2-8
Statements of Equity for the Year Ended December 31, 1997............ F2-9
Statements of Cash Flows for the Year Ended December 31, 1999........ F2-10
Statements of Cash Flows for the Year Ended December 31, 1998........ F2-11
Statements of Cash Flows for the Year Ended December 31, 1997........ F2-12
Notes to the Financial Statements.................................... F2-13
As all Brigham Exploration Company significant 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
separate financial statements.
F1-1
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, of stockholders' equity and of cash flows
present fairly, in all material respects, the financial position of Brigham
Exploration Company at December 31, 1999 and 1998, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1999, in conformity with accounting principles generally accepted
in the United States. 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 auditing standards generally accepted in the
United States, 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
Dallas, Texas
March 7, 2000
F1-2
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands)
December 31,
---------------------------------------
1999 1998
------------------ ---------------
ASSETS
Current assets:
Cash and cash equivalents $ 2,742 $ 2,569
Accounts receivable 4,945 7,938
Other current assets 577 290
------------------ ---------------
Total current assets 8,264 10,797
------------------ ---------------
Natural gas and oil properties, at cost, net 112,066 134,317
Other property and equipment, at cost, net 1,686 2,014
Drilling advances paid 23 230
Deferred loan fees 3,481 3,146
Other noncurrent assets 163 12
------------------ ---------------
$ 125,683 $ 150,516
================== ===============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 14,851 $ 19,883
Accrued drilling costs 541 1,219
Participant advances received 850 764
Other current liabilities 1,502 1,647
------------------ ---------------
Total current liabilities 17,744 23,513
------------------ ---------------
Notes payable 56,000 59,000
Senior subordinated notes, net 41,341 35,786
Other noncurrent liabilities 1,600 7,536
Commitments and contingencies
Stockholders' equity:
Preferred stock, $.01 par value, 10 million shares
authorized, none issued and outstanding - -
Common stock, $.01 par value, 30 million shares
authorized, 14,517,786 and 13,306,206 issued and
outstanding at December 31, 1999 and 1998, respectively 145 133
Additional paid-in capital 64,171 58,838
Unearned stock compensation (290) (890)
Accumulated deficit (55,028) (33,400)
------------------ ---------------
Total stockholders' equity 8,998 24,681
------------------ ---------------
$ 125,683 $ 150,516
================== ===============
Natural gas and oil properties are accounted for using the full cost method.
See accompanying notes to the consolidated financial statements.
F1-3
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
Year Ended December 31,
---------------------------------------------------------------
1999 1998 1997
------------------ ----------------- ------------------
Revenues:
Natural gas and oil sales $ 14,992 $ 13,799 $ 9,184
Workstation revenue 285 390 637
------------------ ----------------- ------------------
15,277 14,189 9,821
------------------ ----------------- ------------------
Costs and expenses:
Lease operating 2,259 2,172 1,151
Production taxes 968 850 549
General and administrative 3,481 4,672 3,570
Depletion of natural gas and oil properties 7,792 8,483 2,743
Depreciation and amortization 525 413 306
Capitalized ceiling impairment - 25,926 -
Amortization of stock compensation 1 372 388
------------------ ----------------- ------------------
15,026 42,888 8,707
------------------ ----------------- ------------------
Operating income (loss) 251 (28,699) 1,114
------------------ ----------------- ------------------
Other income (expense):
Interest income 176 136 145
Interest expense, net (9,697) (5,968) (1,017)
Interest expense - related party - - (173)
Loss on sale of natural gas and oil propertieS (12,195) - -
Other expense (163) - -
------------------ ----------------- ------------------
(21,879) (5,832) (1,045)
------------------ ----------------- ------------------
Net income (loss) before income taxes (21,628) (34,531) 69
Income tax benefit (expense) - 1,186 (1,186)
------------------ ----------------- ------------------
Net loss $ (21,628) $ (33,345) $ (1,117)
================== ================= ==================
Net loss per share:
Basic/Diluted $ (1.53) $ (2.64) $ (0.10)
Weighted average common shares outstanding:
Basic/Diluted 14,152 12,626 11,081
See accompanying notes to the consolidated financial statements.
F1-4
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
(in thousands)
Additional Unearned
Common Stock Paid-in Stock Accumulated Predecessor
------------------------------
Shares Amounts Capital Compensation Deficit Capital Total
-------------- ------------ ----------- -------------- ------------ --------------- -------
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
Net loss - - - - (21,628) - (21,628)
Issuance of
common stock 1,211,580 12 4,228 - - - 4,240
Forfeiture of stock
options - - (602) 602 - - -
Revision in terms
of warrants - - 479 - - - 479
Issuance of warrants - - 1,228 - - - 1,228
Amortization of
unearned stock
compensation - - - (2) - - (2)
----------------- ---------- ---------------- ------------ -------------- -------------- ----------
Balance,
December 31, 1999 14,517,786 $ 145 $ 64,171 $ (290) $ (55,028) $ - $ 8,998
================= ========== ================ ============ ============== ============== ==========
See accompanying notes to the financial statements.
F1-5
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Year ended December 31,
------------------------------------------
1999 1998 1997
----------- ------------ ------------
Cash flows from operating activities:
Net loss $ (21,628) $ (33,345) $ (1,117)
Adjustments to reconcile net loss to cash
provided by operating activities:
Depletion of natural gas and oil properties 7,792 8,483 2,743
Depreciation and amortization 525 413 306
Capitalized ceiling impairment - 25,926 -
Amortization of stock compensation 1 372 388
Interest paid through issuance of additional senior subordinated notes 5,459 - -
Amortization of deferred loan fees and debt issuance costs 1,739 726 -
Amortization of discount on senior subordinated notes 575 286 -
Amortization of deferred loss on derivatives instruments 759 - -
Market value adjustment for derivatives instruments 115 - -
Loss on sale of natural gas and oil properties 12,195 - -
Changes in working capital and other items:
(Increase) decrease in accounts receivable 2,993 (3,029) (2,213)
Increase in other current assets (1,046) (10) (128)
Increase (decrease) in accounts payable (1,136) 7,991 8,955
Increase (decrease) in participant advances received 86 275 (648)
Increase (decrease) in other current liabilities (115) 862 50
Increase in deferred interest payable - related party - - 53
Increase (decrease) in deferred income tax liability - (1,186) 1,186
Other noncurrent assets (151) 6 281
Other noncurrent liabilities (5,585) 7,004 (50)
----------- ------------ ------------
Net cash provided by operating activities 2,578 14,774 9,806
----------- ------------ ------------
Cash flows from investing activities:
Additions to natural gas and oil properties (25,560) (85,207) (57,170)
Proceeds from sale of natural gas and oil properties 27,143 - 74
Additions to other property and equipment (146) (868) (545)
(Increase) decrease in drilling advances paid 207 (152) 341
----------- ------------ ------------
Net cash provided (used) by investing activities 1,644 (86,227) (57,300)
----------- ------------ ------------
Cash flows from financing activities:
Proceeds from issuance of common stock - 9,429 23,927
Proceeds from issuance of sr. subordinated notes payable and warrants - 40,000 -
Increase in notes payable 13,750 105,800 37,250
Repayment of notes payable (16,750) (78,800) (13,250)
Principal payments on capital lease obligations (253) (236) (179)
Deferred loan fees paid (796) (3,872) -
----------- ------------ ------------
Net cash provided (used) by financing activities (4,049) 72,321 47,748
----------- ------------ ------------
Net increase in cash and cash equivalents 173 868 254
Cash and cash equivalents, beginning of period 2,569 1,701 1,447
----------- ------------ ------------
Cash and cash equivalents, end of period $ 2,742 $ 2,569 $ 1,701
=========== ============ ============
Supplemental disclosure of cash flow information:
Cash paid during the period for interest $ 1,960 $ 5,490 $ 1,679
=========== ============ ============
Supplemental disclosure of noncash investing and financing activities:
Capital lease asset additions $ 51 $ 320 $ 403
=========== ============ ============
Decrease in accounts payable and other noncurrent liabilities in
exchange for issuance of common stock $ 4,240
===========
Increase in accounts payable for deferred loan fees to be paid
in future periods $ 50
===========
Increase in deferred loan fees for issuance of warrants $ 1,228
===========
See accompanying notes to the consolidated financial statements.
F1-6
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.
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.
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.
F1-7
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 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.
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
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, 1999, 1998 and 1997 were not significant. Interest is
capitalized on significant unevaluated natural gas and oil properties that are
not subject to amortization.
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
The Company periodically enters into commodity hedge contracts, including
price swaps, caps and/or floors, 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
underlying volumes. The notional amounts of these derivative financial
instruments are based on expected production from existing wells. The Company
uses these derivative financial instruments to manage market risks resulting
from fluctuations in commodity prices.
F1-8
Correlation of the hedge contracts is determined by evaluating whether
hedge contract gains and losses will substantially offset the effects of price
changes on the underlying natural gas and crude oil sales volumes. To the extent
that correlation exists between the hedge contracts and the underlying natural
gas and crude oil sales volumes, realized gains or losses and related cash flows
arising from the hedge contracts are recognized as a component of natural gas
and oil sales in the same period as the sale of the underlying volumes. To the
extent that correlation does not exist between the hedge contracts and the
underlying natural gas and crude oil sales volumes, realized gains or losses and
related cash flows arising from the hedge contracts are recognized in the period
incurred as a component of other income. The fair market value of any hedge
contract that does not meet the correlation test outlined above is recorded as a
deferred gain or loss on the balance sheet and is adjusted to current market
value at each balance sheet date with any deferred gains or losses recognized as
a component of other income.
In the event that management decides to terminate a hedge contract,
generally accepted accounting principles require that any gains or losses upon
termination be carried forward and recognized as a component of natural gas and
oil sales in the period in which the underlying volumes are sold.
Stock Based Compensation
The Company measures compensation expense for its stock based incentive
plan using the intrinsic value method and has provided in Note 11 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.
Segment Information
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.
F1-9
New Pronouncements
In June 1998, the Financial Accounting Standards Board (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, as
amended by SFAS No. 137, effective January 1, 2001. The Company is in the
process of analyzing the potential impact of this standard on its financial
statement presentations.
3. Asset Dispositions
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.
In June 1999, the Company sold its entire interest in certain producing and
non-producing natural gas and oil properties located in its Anadarko Basin
province to two parties for a combined sales price of $17.1 million. Total
proceeds, net of transaction costs, were $16.7 million and were used to repay a
portion of the Company's notes payable. Due to the magnitude of the reserve
volumes that were attributable to these properties relative to the Company's
remaining net reserve volumes, the Company recognized a loss of $12.2 million,
which was difference between the sales price received, after adjustment for
transaction costs, and the $28.9 million basis allocated to the divested
properties in accordance with the full-cost method of accounting for oil and gas
properties.
F1-10
4. Property and Equipment
Property and equipment, at cost, are summarized as follows (in
thousands):
December 31,
------------------------------
1999 1998
------------- --------------
Natural gas and oil properties....................... $ 178,755 181,019
Accumulated depletion................................ (66,689) (46,702)
------------- --------------
112,066 134,317
------------- --------------
Other property and equipment:
3-D seismic interpretation workstations
and software.................................... 2,248 2,186
Office furniture and equipment.................... 1,909 1,774
Accumulated depreciation.......................... (2,471) (1,946)
------------- --------------
1,686 2,014
------------- --------------
$ 113,752 $ 136,331
============= ==============
At December 31, 1998, a capitalized ceiling impairment of $25.9 million was
recognized and is included above in the accumulated depletion balances for
natural gas and oil properties. 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.
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. During the years ended December 31, 1999, 1998 and 1997, these
capitalized costs amounted to $3.3 million, $4.6 million and $3.5 million,
respectively. Capitalized costs do not include any costs related to production,
general corporate overhead, or similar activities. Interest costs of $3.0
million and $1.2 million were capitalized in 1999 and 1998, respectively.
5. Notes Payable and Senior Subordinated Notes Payable
In January 1998, the Company entered into a reserve-based revolving credit
facility (the "Credit Facility") which originally provided for initial borrowing
availability of $75 million. 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 accrued 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 was amended in March 1999 to reduce the borrowing
availability, extend the date of borrowing base redetermination, modify certain
financial covenants, include certain additional covenants that place significant
restrictions on the Company's ability to make certain capital expenditures, and
to change the interest rate on outstanding borrowings to either the lender's
Base Rate or LIBOR plus 3.0%, at the Company's option. The Company incurred a
$500,000 transaction fee due to the lender over a ten month period.
In July 1999, the Credit Facility was amended to provide the Company with
borrowing availability of $56 million. As consideration for this amendment, in
July 1999 the Company issued to its senior lenders one million warrants to
purchase the Company's common stock at an exercise price of $2.25 per share. An
estimated value of $1.2 million was attributed to these warrants by the Company
and was recognized as additional deferred loan fees to be amortized over the
remaining period to maturity of the Credit Facility. 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.
F1-11
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.
Principal outstanding under the Notes is due at maturity on August 20,
2003. Interest on the 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 Notes. Interest is payable in cash at interest rates of 12%, 13%,
and 14% during the years one through three, year four and year five,
respectively, of the term of the Notes; provided, however, that the Company may
pay interest in kind for a cumulative total of seven (or potentially eight)
quarterly interest payments at interest rates of 13%, 14% and 15% during the
years one through three, year four and year five, respectively, of the term of
the Notes. 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. Additionally,
the stock of certain subsidiaries has also been pledged as collateral for the
Notes. 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. The discount on the Notes was decreased by $479,000 to reflect the change
in value attributed to the Warrants as a result of the revision in the terms of
the Warrants.
F1-12
6. Capital Lease Obligations
Property under capital leases consists of the following (in thousands):
December 31,
------------------------------
1999 1998
------------- --------------
3-D seismic interpretation workstations and software....................... $ 607 $ 620
Office furniture and equipment............................................. 167 167
------------- --------------
774 787
Accumulated depreciation and amortization.................................. (410) (276)
------------- --------------
$ 364 $ 511
============= ==============
The obligations under capital leases are at fixed interest rates ranging
from 7.5% 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, 1999 are as follows (in
thousands):
2000...................................................... $ 258
2001...................................................... 115
2002...................................................... 27
-------------
Total minimum lease payments.............................. 400
Estimated executory costs included in capital leases... (25)
-------------
Net minimum lease payments................................ 375
Amounts representing interest.......................... (38)
-------------
Present value of net minimum lease payments............... 337
Less: current portion.................................... (210)
-------------
Noncurrent portion........................................ $ 127
=============
7. Income Taxes
The provision for income taxes consists of the following (in thousands):
Year ended
December 31,
------------------------------
1999 1998
------------- --------------
Current income taxes:
Federal............................... $ - $ -
State................................. - -
Deferred income taxes:
Federal............................... - (1,186)
State................................. - -
------------- --------------
$ - $ (1,186)
============= ==============
F1-13
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):
Year ended
December 31,
------------------------------
1999 1998
------------- --------------
Tax at statutory rate................... $ (7,570) $ (11,740)
Add the effect of:
Nondeductible expenses............... 8 10
Valuation reserve.................... 7,562 10,544
------------- --------------
$ - $ (1,186)
============= ==============
The components of deferred income tax assets and liabilities are as follows
(in thousands):
December 31,
-----------------------------
1999 1998
------------ --------------
Deferred tax assets:
Net operating loss carryforwards........ $ 18,796 $ 11,219
Amortization of stock compensation...... 266 258
Other................................... 27 3
------------ --------------
19,089 11,480
Deferred tax liability:
Depreciable and depletable property..... (484) (936)
Valuation reserve....................... (18,605) (10,544)
------------ --------------
$ - $ -
============ ==============
At December 31, 1999, the Company had regular and alternative minimum tax
net operating loss carryforwards of approximately $53.7 million and $45.2
million, respectively, which expire by December 31, 2019.
8. Net Income (Loss) Per Share
Net loss per share is presented in the consolidated financial statements
based on a basic loss per share calculation as well as a diluted loss per share
calculation. Basic loss per share is computed by dividing net loss applicable to
common shareholders by the weighted average number of common shares outstanding
during each period. Diluted loss per share is computed by dividing net 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.
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, 1999 and 1998, options and warrants to purchase
3,519,726 and 2,194,654 shares of common stock, respectively, were outstanding
but were not included in the computation of diluted loss per share because they
were anti-dilutive.
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.
F1-14
As of December 31, 1999, 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, 1999, are
as follows (in thousands):
2000....................................................... $ 795
2001....................................................... 790
2002....................................................... 395
-------------
$ 1,980
=============
Rental expense for the years ended December 31, 1999, 1998 and 1997 was
$937,669, $875,150 and $606,173, respectively.
Major Customers
During 1999, approximately 26%, 16% and 11% of the Company's natural gas
and oil production was sold to three separate customers. 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. However, due to the availability of other customers, the Company does
not believe that the loss of any one of these individual customers would
adversely affect the Company's result of operations.
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.
10. 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.
In 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. 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.
F1-15
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.
As a result of these arrangements, the Company realized an increase
(decrease) in natural gas and oil revenues of approximately $(486,000), $555,000
and $(6,200) during 1999, 1998 and 1997, respectively. To the extent that
notional amounts covered by these arrangements exceed actual production
quantities, a corresponding portion of the contracts has been recorded on the
balance sheet at fair value, which approximated $291,000 as of December 31,
1999. Additionally, the mark-to-market adjustments and related cash flows
associated with this portion of these contracts of approximately $(429,000) have
been recorded as a component of other income (expense) on the 1999 statement of
operations.
In September 1999, the Company amended the fixed contract price from $2.065
per MMBtu to a range from $2.509 to $2.678 per MMBtu for natural gas volumes for
the months of October 1999 through January 2000 under the then outstanding swap
agreement. This resulted in a deferred loss of $1.1 million to be amortized to
natural gas and oil revenues over the original contract period of October 1999
through January 2000. During 1999, approximately $645,000 was amortized to
natural gas and oil revenues.
Concurrently, in September 1999 the Company entered into natural gas and
crude oil cap contracts. The natural gas cap contract provides the counterparty
with a call option on 10,000 MMBtu per day of natural gas production for the
monthly periods from May 2001 through June 2002. Payments are made by the
Company to the counterparty when the floating price exceeds the fixed price of
$2.50 per MMBtu for the periods May 2001 through October 2001 and May 2002
through June 2002, and $2.70 per MMBtu for the period November 2001 through
April 2002.
These instruments do not qualify for hedge accounting and accordingly were
recorded on the date of the transaction at their fair value of $1.1 million as a
deferred credit on the balance sheet. As of December 31, 1999, the fair value of
the remaining contracts approximated $875,000 million with the corresponding
mark-to-market adjustments and related cash flows recorded as a component of
other income (expense) on the statement of operations.
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 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, 1999 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.
F1-16
11. Employee Benefit Plans
Retirement Savings Plan
The Company has 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.
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 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. No compensation expense resulted 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 over
three to five 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 market value of the Company's common stock on
the date of grant and generally vest over five years.
F1-17
The following table summarizes activity under the incentive plan for
each of the three years ended December 31, 1999:
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
Options granted........................ 650,000 2.43
Options forfeited or cancelled......... (324,928) (4.68)
Options exercised...................... - -
------------- ------------
Options outstanding December 31, 1999....... 1,519,726 $ 4.47
============= ============
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 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, 1999 range from
$1.5545 to $14.375 and remaining contractual lives range from 4.5 to 7 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.
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. Options
exercisable at December 31, 1999, 1998 and 1997 were 291,242, 145,740 and zero,
respectively.
The weighted average fair value per share of stock compensation issued
during 1999, 1998 and 1997 was $1.42, $5.40 and $6.24, respectively. The fair
value for these options was estimated using the Black-Scholes model with the
following weighted average assumptions for grants made in 1999, 1998 and 1997:
risk free interest rate of 6.0%, 4.7% and 6.2%; volatility of the expected
market prices of the Company's common stock of 57%, 77% and 38%; expected
dividend yield of zero and weighted average expected option lives of 5.6, 5.0
and 7.3 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 1999, 1998 and 1997 would have been the pro forma amounts indicated
below:
F1-18
1999 1998 1997
------------ ------------ ----------
Net loss (in thousands):
As reported.................. $ (21,628) $ (33,345) $ (1,117)
Pro forma.................... (21,605) (33,591) (1,314)
Net loss per share:
As reported.................. (1.53) (2.64) (0.10)
Pro forma.................... (1.53) (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. In January 1998, the
Company revised the fair market value of its common stock at the date these
options were granted from $8.00 to $9.00. The result of this revision was an
increase in the 1997 net loss of approximately $81,000, or $0.01 per share.
12. Related Party Transactions
During the years ended December 31, 1999, 1998 and 1997, the Company
incurred costs of approximately $180,000, $851,000 and $837,000 respectively,
for 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 1997, the Company paid $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.
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 $62,874, $100,539 and $86,580 for the years ended
December 31, 1999, 1998 and 1997, respectively. Additional disbursements
totaling approximately $12,000, $12,000 and $13,000 were made during 1999, 1998
and 1997, respectively, for the reimbursement of certain expenses.
13. Subsequent Event
In February 2000, the Company entered into an amended and restated Credit
Facility with its existing lenders and a new lender. This amended and restated
Credit Facility provides the Company with an increase to $70 million in
borrowing availability for a three-year term. If the Company exceeds certain
asset value and interest coverage tests in the second or third quarters of 2000,
the total borrowing availability under the Credit Facility will increase to $75
million. Borrowings under the Credit Facility in excess of $45 million are
convertible into shares of the Company's common stock in the following amounts:
(i) the first $10 million of borrowings is convertible at $3.90 per share, (ii)
the second $10 million is convertible at $6.00 per share, and (iii) the final
$10 million is convertible at $8.00 per share. If the Credit Facility is repaid
at maturity or is prepaid prior to maturity without payment of cash premiums,
the Company must issue to a new lender of the Credit Facility warrants to
purchase shares of the Company's common stock. In addition, certain financial
covenants of the Credit Facility have been amended or added. In connection with
this most recent amendment, the Company reset the price of the warrants
previously issued to its existing senior lenders to purchase one million shares
of the Company's common stock from an exercise price of $2.25 per share to $2.02
per share.
In February 2000, the indenture governing the Notes was amended. The
holders of the Notes waived the minimum consolidated interest coverage ratio
covenant through June 30, 2000 and adjusted subsequent levels under this test.
In addition, an amendment to the Notes provides the Company with an extension of
its right to pay interest through the issuance of additional Notes in lieu of
cash (or "in kind") through the third quarter of 2000 and potentially through
the fourth quarter of 2000 if certain conditions are met. In exchange for
granting these amendments, the Company has (i) reset the price of the warrants
previously issued to the holders of the Notes to purchase one million shares of
the Company's common stock from an exercise price of $3.50 per share to $2.43
per share and (ii) granted to the holders of the Notes a term overriding royalty
interest that provides for the limited right to receive 4%, or 3% if certain
conditions are met, of the Company's net production revenue to reduce any
outstanding Notes issued as interest paid in kind.
F1-19
14. 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,
-------------------------------------
1999 1998 1997
----------- ------------ ----------
Natural gas and oil sales......................... $ 14,992 $ 13,799 $ 9,184
Costs and expenses:
Lease operating................................ 2,259 2,172 1,151
Production taxes............................... 968 850 549
Depletion of natural gas and oil properties.... 7,792 8,483 2,743
Capitalized ceiling impairment................. - 25,926 -
Income tax expense (benefit) (a)............... 1,391 (8,271) 1,318
----------- ------------ ----------
Total costs and expenses.......................... 12,410 29,160 5,761
----------- ------------ ----------
$ 2,582 $ (15,361) $ 3,423
=========== ============ ==========
Depletion per physical unit of production
(equivalent Mcf of gas)........................ $ 1.24 $ 1.27 $ 0.88
=========== ============ ==========
- ------------
(a) The income tax expense (benefit) 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. 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.
F1-20
Costs Incurred and Capitalized Costs
The costs incurred in natural gas and oil acquisition, exploration and
development activities follow (in thousands):
December 31,
----------------------------------------
1999 1998 1997
------------ ------------ ------------
Costs incurred for the year:
Exploration................. $ 19,224 $ 68,214 $ 29,516
Property acquisition........ 3,462 16,245 26,956
Development................. 4,632 10,475 2,953
Proceeds from participants.. (2,439) (10,502) (319)
------------ ------------ ------------
$ 24,879 $ 84,432 $ 59,106
============ ============ ============
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,
------------------------------
1999 1998
------------- --------------
Cost of natural gas and oil properties
at year-end:
Proved................................. $ 140,757 $ 128,643
Unproved............................... 37,998 52,376
------------- --------------
Total capitalized costs................ 178,755 181,019
Accumulated depletion.................. (66,689) (46,702)
------------- --------------
$ 112,066 $ 134,317
============= ==============
Following is a summary of costs (in thousands) excluded from depletion at
December 31, 1999, 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
------------------------------------
1999 1998 1997 Years Total
----------- ----------- ---------- ---------- ----------
Property acquisition... $ 1,079 $ 6,414 $ 5,558 $ 1,921 $ 14,972
Exploration............ 1,174 12,876 7,404 1,572 23,026
----------- ----------- ---------- ---------- ----------
Total.................. $ 2,253 $ 19,290 $ 12,962 $ 3,493 $ 37,998
=========== =========== ========== ========== ==========
15. 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.
F1-21
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.
Natural
Gas Oil
(MMcf) (MBbls)
------------- --------------
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 to 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
Revisions of previous estimates............... (9,938) 214
Extensions, discoveries and other additions... 30,428 1,156
Sales of minerals-in-place.................... (22,002) (2,430)
Production.................................... (4,197) (346)
------------- --------------
Proved reserves at December 31, 1999............. 65,457 3,027
============= ==============
Proved developed reserves at December 31:
1997.......................................... 30,677 2,665
1998.......................................... 38,571 2,935
1999.......................................... 28,594 1,873
Proved reserves are estimated quantities of natural gas and crude 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.
F1-22
December 31,
----------------------------------------
1999 1998 1997
------------ ------------ ------------
Future cash inflows.......................................... $ 228,429 $ 198,082 $ 165,156
Future development and production costs...................... (61,878) (61,064) (40,923)
Future income taxes.......................................... (12,406) (6,972) (22,919)
------------ ------------ ------------
Future net cash inflows...................................... $ 154,145 $ 130,046 $ 101,314
============ ============ ============
Future net cash inflow before income taxes, discounted
at 10% per annum.......................................... $ 114,466 $ 81,741 $ 69,249
============ ============ ============
Standardized measure of future net cash inflows discounted
at 10% per annum.......................................... $ 113,546 $ 81,649 $ 44,506
============ ============ ============
The base sales prices for the Company's reserves were $2.35 per Mcf for
natural gas and $22.75 per Bbl for oil as of December 31, 1999, $2.12 per Mcf
for natural gas and $9.50 per Bbl for oil as of December 31, 1998, and $2.27 per
Mcf for natural gas and $15.50 per Bbl for oil as of December 31, 1997. 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
(in thousands):
December 31,
----------------------------------------
1999 1998 1997
------------ ------------ ------------
Beginning of period............................................. $ 81,649 $ 64,274 $ 44,506
Sales of natural gas and oil produced, net of production
costs................................................... (11,765) (10,776) (7,484)
Development costs incurred................................... 4,413 5,423 1,955
Extensions and discoveries................................... 43,346 52,389 38,016
Purchases of minerals-in-place............................... - 687 16,965
Sales of minerals-in-place................................... (32,783) - (94)
Net change of prices and production costs.................... 33,226 (11,921) (20,466)
Change in future development costs........................... (555) (656) 319
Changes in production rates and other........................ 637 (6,109) (1,954)
Revisions of quantity estimates.............................. (11,969) (23,470) (6,964)
Accretion of discount........................................ 8,174 6,925 4,450
Change in income taxes....................................... (827) 4,883 (4,975)
------------ ------------ ------------
End of period................................................... $ 113,546 $ 81,649 $ 64,274
============ ============ ============
F1-23
16. Quarterly Financial Data (Unaudited)
The Company has restated previously reported quarterly financial results
for the nine months ended September 30, 1999 and the year ended December 31,
1998 to give effect to the capitalization of interest for significant
acquisition, exploration and development activities in progress. There was no
effect on the year ended December 31, 1998 net loss or on the 1997 financial
results. The effect of this restatement on the statement of operations is as
follows (in thousands, except per share amounts):
Year Ended December 31, 1999
------------------------------------------------------------------------------------
Quarter 1 Quarter 2 Quarter 3 Quarter 4
------------------------ ---------------------- ------------------------ -----------
Previously As Previously As Previously As
Reported Restated Reported Restated Reported Restated
------------- ----------- ----------- ---------- ----------- -----------
Revenue........................... $ 3,281 $ 3,281 $ 3,626 $ 3,624 $ 4,195 $ 4,238 $ 4,134
Operating income (loss)........... 124 113 245 190 (379) (432) 380
Net loss.......................... (2,669) (1,944) (15,034) (14,839) (3,589) (2,651) (2,194)
Net loss per share:
Basic/Diluted................ (0.20) (0.15) (1.05) (1.04) (0.25) (0.18) (0.15)
Year Ended December 31, 1998
-----------------------------------------------------------------------------------------------
Quarter 1 Quarter 2 Quarter 3 Quarter 4
-----------------------------------------------------------------------------------------------
Previously As Previously As Previously As Previously As
Reported Restated Reported Restated Reported Restated Reported Restated
------------- ---------- ----------- ----------- ----------- ---------- ----------- -----------
Revenue.................. $ 3,257 $ 3,257 $ 4,120 $ 4,120 $ 4,237 $ 4,237 $ 2,575 $ 2,575
Operating income (loss).. 31 27 427 413 481 466 (28,486) (29,605)
Net loss................. (632) (460) (627) (461) (964) (777) (31,122) (31,647)
Net loss per share:
Basic/Diluted....... (0.05) (0.04) (0.05) (0.04) (0.08) (0.06) (2.34) (2.34)
F1-24
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors
and Stockholders of Brigham Exploration Company
In our opinion, the accompanying balance sheets and the related statements of
operations, of changes in equity and of cash flows, present fairly in all
material respects, the financial position of Brigham Oil & Gas, L.P., and
Brigham, Inc. at December 31, 1999 and 1998, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1999, in conformity with accounting principles generally accepted in the
United States. Additionally, in our opinion, the accompanying balance sheets and
the related statements of operations, of changes in equity and of cash flows
present fairly, in all material respects, the financial position of Brigham
Holdings I, LLC and Brigham Holdings II, LLC at December 31, 1999 and 1998 and
for the two years then ended, in conformity with accounting principles generally
accepted in the United States. 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 auditing standards generally accepted in the
United States, 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
Dallas, Texas
March 7, 2000
F2-1
BRIGHAM EXPLORATION COMPANY SUBSIDIARIES
BALANCE SHEETS
As of December 31, 1999
(in thousands)
Brigham Brigham Brigham
Oil & Brigham, Holdings Holdings
Gas, L.P. Inc. I, LLC II, LLC
ASSETS
Current assets:
Cash and cash equivalents $ 2,718 $ 2,736 $ 6 $ 6
Accounts receivable 4,945 4,945 - -
Other current assets 577 577 - -
---------------- ---------------- -------------- ---------------
Total current assets 8,240 8,258 6 6
---------------- ---------------- -------------- ---------------
Natural gas and oil properties, at cost, net 112,066 112,066 - -
Other property and equipment, at cost, net 1,686 1,686 - -
Investment in subsidiaries
and intercompany advances 130 26 1,299 47,802
Drilling advances paid 23 23 - -
Deferred loan fees 2,108 2,108 - -
Other noncurrent assets 164 164 - -
---------------- ---------------- -------------- ---------------
$ 124,417 $ 124,331 $ 1,305 $ 47,808
================ ================ ============== ===============
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable $ 14,851 $ 14,851 $ - $ -
Accrued drilling costs 541 541 - -
Participant advances received 850 850 - -
Other current liabilities 1,429 1,429 - -
---------------- ---------------- -------------- ---------------
Total current liabilities 17,671 17,671 - -
---------------- ---------------- -------------- ---------------
Notes payable 56,000 56,000 - -
Other noncurrent liabilities 1,600 1,600 - -
Intercompany accounts payable 1,752 1,687 - 1,779
Intercompany notes payable 45,459 45,459 - 45,459
Commitments and contingencies
Minority interest - 1,325 - -
Equity
Partners' capital 1,935 - 1,305 570
Common stock, $1.00 par value, 1,000
shares authorized, issued and
outstanding - 1 - -
Additional paid-in capital - 17,832 - -
Accumulated deficit - (17,244) - -
---------------- ---------------- -------------- ---------------
Total equity 1,935 589 1,305 570
---------------- ---------------- -------------- ---------------
$ 124,417 $ 124,331 $ 1,305 $ 47,808
================ ================ ============== ===============
Natural gas and oil properties are accounted for using the full cost method.
See accompanying notes to the financial statements.
F2-2
BRIGHAM EXPLORATION COMPANY SUBSIDIARIES
BALANCE SHEETS
As of December 31, 1998
(in thousands)
Brigham Brigham Brigham
Oil & Brigham, Holdings Holdings
Gas, L.P. Inc. I, LLC II, LLC
ASSETS
Current assets:
Cash and cash equivalents $ 2,549 $ 2,563 $ 5 $ 6
Accounts receivable 7,938 7,938 - -
Other current assets 290 290 - -
---------------- ---------------- ------------- ---------------
Total current assets 10,777 10,791 5 6
---------------- ---------------- ------------- ---------------
Natural gas and oil properties, at cost, net 134,317 134,317 - -
Other property and equipment, at cost, net 2,014 2,014 - -
Investment in subsidiaries
and intercompany advances 115 16 11,714 46,913
Drilling advances paid 231 231 - -
Deferred loan fees 1,397 1,397 - -
Other noncurrent assets 12 12 - -
---------------- ---------------- ------------- ---------------
$ 148,863 $ 148,778 $ 11,719 $ 46,919
================ ================ ============= ===============
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable $ 19,883 $ 19,883 $ - $ -
Accrued drilling costs 1,219 1,219 - -
Participant advances received 764 764 - -
Other current liabilities 1,647 1,647 - -
---------------- ---------------- ------------- ---------------
Total current liabilities 23,513 23,513 - -
---------------- ---------------- ------------- ---------------
Notes payable 59,000 59,000 - -
Other noncurrent liabilities 7,536 7,536 - -
Intercompany accounts payable 1,690 1,616 - 1,707
Intercompany notes payable 40,000 40,000 - 40,000
Commitments and contingencies
Minority interest - 11,730 - -
Equity
Partners' capital 17,124 - 11,719 5,212
Common stock, $1.00 par value, 1,000
shares authorized, issued and
outstanding - 1 - -
Additional paid-in capital - 16,109 - -
Accumulated deficit - (10,727) - -
---------------- ---------------- -------------- ---------------
Total equity 17,124 5,383 11,719 5,212
---------------- ---------------- -------------- ---------------
$ 148,863 $ 148,778 $ 11,719 $ 46,919
================ ================ ============== ===============
Natural gas and oil properties are accounted for using the full cost method.
See accompanying notes to the financial statements.
F2-3
BRIGHAM EXPLORATION COMPANY SUBSIDIARIES
STATEMENTS OF OPERATIONS
For the Year Ended December 31, 1999
(in thousands)
Brigham Brigham Brigham
Oil & Brigham, Holdings Holdings
Gas, L.P. Inc. I, LLC II, LLC
Revenues:
Natural gas and oil sales $ 14,992 $ 14,992 $ - $ -
Workstation revenue 285 285 - -
------------- ------------- -------------- --------------
15,277 15,277 - -
------------- ------------- -------------- --------------
Costs and expenses:
Lease operating 2,259 2,259 - -
Production taxes 968 968 - -
General and administrative 3,462 3,472 9 9
Depletion of natural gas and oil properties 7,792 7,792 - -
Depreciation and amortization 525 525 - -
Amortization of stock compensation 1 1 - -
------------- ------------- -------------- --------------
15,007 15,017 9 9
------------- ------------- -------------- --------------
Operating income (loss) 270 260 (9) (9)
------------- ------------- -------------- --------------
Other income (expense):
Interest income 176 176 - -
Interest expense, net (3,214) (3,214) - -
Interest expense - intercompany (5,532) (5,532) - (5,532)
Loss on sale of natural gas and
oil properties (12,195) (12,195) - -
Other expense (163) (163) - -
------------- ------------- -------------- --------------
(20,928) (20,928) - (5,532)
------------- ------------- -------------- --------------
Minority interest in net loss - (14,151) - -
------------- ------------- -------------- --------------
Net loss before income taxes (20,658) (6,517) (9) (5,541)
Income tax benefit - - - -
Equity in net loss of investee - - (14,151) (769)
------------- ------------- -------------- --------------
Net loss $ (20,658) $ (6,517) $ (14,160) $ (6,310)
============= ============= ============== ==============
See accompanying notes to the financial statements.
F2-4
BRIGHAM EXPLORATION COMPANY SUBSIDIARIES
STATEMENTS OF OPERATIONS
For the Year Ended December 31, 1998
(in thousands)
Brigham Brigham Brigham
Oil & Brigham, Holdings Holdings
Gas, L.P. Inc. I, LLC II, LLC
Revenues:
Natural gas and oil sales $ 13,799 $ 13,799 $ - $ -
Workstation revenue 390 390 - -
------------- ------------- -------------- --------------
14,189 14,189 - -
------------- ------------- -------------- --------------
Costs and expenses:
Lease operating 2,172 2,172 - -
Production taxes 850 850 - -
General and administrative 4,650 4,661 11 11
Depletion of natural gas and oil properties 8,483 8,483 - -
Depreciation and amortization 413 413 - -
Capitalized ceiling impairment 25,926 25,926 - -
Amortization of stock compensation 372 372 - -
------------- ------------- -------------- --------------
42,866 42,877 11 11
------------- ------------- -------------- --------------
Operating loss (28,677) (28,688) (11) (11)
------------- ------------- -------------- --------------
Other income (expense):
Interest income 136 136 - -
Interest expense, net (3,841) (3,841) - -
Interest expense - intercompany (1,707) (1,707) - (1,707)
------------- ------------- -------------- --------------
(5,412) (5,412) - (1,707)
------------- ------------- -------------- --------------
Minority interest in net loss - (23,351) - -
------------- ------------- -------------- --------------
Net loss before income taxes (34,089) (10,749) (11) (1,718)
Income tax benefit - 5,088 - -
Equity in net loss of investee - - (23,351) (8,690)
------------- ------------- -------------- --------------
Net loss $ (34,089) $ (5,661) $ (23,362) $ (10,408)
============= ============= ============== ==============
See accompanying notes to the financial statements.
F2-5
BRIGHAM EXPLORATION COMPANY SUBSIDIARIES
STATEMENTS OF OPERATIONS
For the Year Ended December 31, 1997
(in thousands)
Brigham
Oil & Brigham,
Gas, L.P. Inc.
Revenues:
Natural gas and oil sales $ 9,184 $ 9,184
Workstation revenue 637 637
-------------- ---------------
9,821 9,821
-------------- ---------------
Costs and expenses:
Lease operating 1,151 1,151
Production taxes 549 549
General and administrative 3,570 3,570
Depletion of natural gas and oil properties 2,743 2,743
Depreciation and amortization 306 306
Amortization of stock compensation 388 388
-------------- ---------------
8,707 8,707
-------------- ---------------
Operating income 1,114 1,114
-------------- ---------------
Other income (expense):
Interest income 145 145
Interest expense, net (1,017) (1,017)
Interest expense - related party (173) (173)
-------------- ---------------
(1,045) (1,045)
-------------- ---------------
Minority interest in net income - 47
-------------- ---------------
Net income before income taxes 69 22
Income tax expense - (5,088)
-------------- ---------------
Net income (loss) $ 69 $ (5,066)
============== ==============
See accompanying notes to the financial statements.
F2-6
BRIGHAM EXPLORATION COMPANY SUBSIDIARIES
STATEMENTS OF CHANGES IN EQUITY
(in thousands, except shares)
Retained
Additional Earnings/
Common Stock Paid-in Accumulated Partners'
---------------------
Shares Amounts Capital Deficit Capital Total
--------- ---------------------- -------------- -------------- --------------
Brigham Oil & Gas, L.P.
Balance,
December 31, 1998 - $ - $ - $ - $ 17,124 $ 17,124
Capital contribution - - - - 5,469 5,469
Net loss - - - (20,658) (20,658)
--------- ---------- ------------ -------------- -------------- --------------
Balance,
December 31, 1999 - $ - $ - $ - $ 1,935 $ 1,935
========= ========== ============ ============== ============== ==============
Brigham Inc.
Balance,
December 31, 1998 1,000 $ 1 $ 16,109 $ (10,727) $ - $ 5,383
Capital contribution - - 1,723 - - 1,723
Net loss - - - (6,517) - (6,517)
--------- ---------- ------------ -------------- -------------- --------------
Balance,
December 31, 1999 1,000 $ 1 $ 17,832 $ (17,244) $ - $ 589
========= ========== ============ ============== ============== ==============
Brigham Holding I, LLC
Balance,
December 31, 1998 - $ - $ - $ - $ 11,719 $ 11,719
Capital contribution - - - - 3,746 3,746
Net loss - - - - (14,160) (14,160)
--------- ---------- ------------ -------------- -------------- --------------
Balance,
December 31, 1999 - $ - $ - $ - $ 1,305 $ 1,305
========= ========== ============ ============== ============== ==============
Brigham Holdings II, LLC
Balance,
December 31, 1998 - $ - $ - $ - $ 5,212 $ 5,212
Capital contribution - - - - 1,668 1,668
Net loss - - - - (6,310) (6,310)
--------- ---------- ------------ -------------- -------------- --------------
Balance,
December 31, 1999 - $ - $ - $ - $ 570 $ 570
========= ========== ============ ============== ============== ==============
See accompanying notes to the financial statements.
F2-7
BRIGHAM EXPLORATION COMPANY SUBSIDIARIES
STATEMENTS OF CHANGES IN EQUITY
(in thousands, except shares)
Retained
Additional Earnings/
Common Stock Paid-in Accumulated Partners'
---------------------
Shares Amounts Capital Deficit Capital Total
--------- ---------------------- -------------- -------------- --------------
Brigham Oil & Gas, L.P.
Balance,
December 31, 1997 - $ - $ - $ - $ 43,665 $ 43,665
Capital contribution - - - - 7,548 7,548
Net loss - - - (34,089) (34,089)
--------- ---------- ------------ -------------- -------------- --------------
Balance,
December 31, 1998 - $ - $ - $ - $ 17,124 $ 17,124
========= ========== ============ ============== ============== ==============
Brigham Inc.
Balance,
December 31, 1997 1,000 $ 1 $ 13,732 $ (5,066) $ - $ 8,667
Capital contribution - - 2,377 - - 2,377
Net loss - - - (5,661) - (5,661)
--------- ---------- ------------ -------------- -------------- --------------
Balance,
December 31, 1998 1,000 $ 1 $ 16,109 $ (10,727) $ - $ 5,383
========= ========== ============ ============== ============== ==============
Brigham Holding I, LLC
Balance,
December 31, 1997 - $ - $ - $ - $ - $ -
Partnership interest
contributed - - - - 29,911 29,911
Capital contribution - - - - 5,170 5,170
Net loss - - - - (23,362) (23,362)
--------- ---------- ------------ -------------- -------------- --------------
Balance,
December 31, 1998 - $ - $ - $ - $ 11,719 $ 11,719
========= ========== ============ ============== ============== ==============
Brigham Holdings II, LLC
Balance,
December 31, 1997 - $ - $ - $ - $ - $ -
Partnership interest
contributed - - - - 13,318 13,318
Capital contribution - - - - 2,302 2,302
Net loss - - - - (10,408) (10,408)
--------- ---------- ------------ -------------- -------------- --------------
Balance,
December 31, 1998 - $ - $ - $ - $ 5,212 $ 5,212
========= ========== ============ ============== ============== ==============
See accompanying notes to the financial statements.
F2-8
BRIGHAM EXPLORATION COMPANY SUBSIDIARIES
STATEMENTS OF CHANGES IN EQUITY
(in thousands)
Retained
Additional Earnings/
Common Stock Paid-in Accumulated Partners'
---------------------
Shares Amounts Capital Deficit Capital Total
--------- ---------------------- -------------- -------------- --------------
Brigham Oil & Gas, L.P.
Balance,
December 31, 1996 - $ - $ - $ - $ 3,244 $ 3,244
Capital contribution from
Brigham Exploration
Company at consummation
of Exchange - - - - 16,425 16,425
Capital contribution from
Brigham Exploration
Company of proceeds
from Offering - - - - 23,927 23,927
Net income - - - - 69 69
--------- ---------- ------------ -------------- -------------- --------------
Balance,
December 31, 1997 - $ - $ - $ - $ 43,665 $ 43,665
========= ========== ============ ============== ============== ==============
Brigham Inc.
Balance,
December 31, 1996 1,000 $ 1 $ 29 $ - $ - $ 30
Increase in equity due to
change in ownership in
the Partnership resulting
from the Exchange and
the Offering - - 13,703 - - 13,703
Net loss - - - (5,066) - (5,066)
--------- ---------- ------------ -------------- -------------- --------------
Balance,
December 31, 1997 1,000 $ 1 $ 13,732 $ (5,066) $ - $ 8,667
========= ========== ============ ============== ============== ==============
See accompanying notes to the financial statements.
F2-9
BRIGHAM EXPLORATION COMPANY SUBSIDIARIES
STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 1999
(in thousands)
Brigham Brigham Brigham
Oil & Brigham, Holdings Holdings
Gas, L.P. Inc. I, LLC II, LLC
Cash flows from operating activities:
Net loss $ (20,658) $ (6,517) $ (14,160) $ (6,310)
Adjustments to reconcile net loss to cash
provided by operating activities:
Depletion of natural gas and oil properties 7,792 7,792 - -
Depreciation and amortization 525 525 - -
Amortization of stock compensation 1 1 - -
Amortization of deferred loan fees and debt issuance costs 1,363 1,363 - -
Amortization of deferred loss on derivatives instruments 759 759 - -
Market value adjustment for derivatives instruments 115 115 - -
Loss on sale of natural gas and oil properties 12,195 12,195 - -
Minority interest in net loss - (14,151) - -
Equity in net loss of investee - - 14,151 769
Changes in working capital and other items:
Decrease in accounts receivable 2,993 2,993 - -
Increase in other current assets (1,046) (1,046) - -
Decrease in accounts payable (1,136) (1,136) - -
Increase in participant advances received 86 86 - -
Decrease in other current liabilities (188) (188) - -
Increase in intercompany accounts payable 65 74 - 72
Other noncurrent assets (151) (151) - -
Other noncurrent liabilities (5,585) (5,585) - -
------------ ------------- ------------- ---------------
(2,870) (2,871) (9) (5,469)
------------ ------------- ------------- ---------------
Cash flows from investing activities:
Natural gas and oil properties (25,560) (25,560) - -
Proceeds from sale of natural gas and oil properties 27,143 27,143 - -
Other property and equipment (146) (146) - -
Investment in subsidiaries and intercompany advances (15) (10) 10 10
Change in drilling advances paid 207 207 - -
------------ ------------- ------------- ---------------
1,629 1,634 10 10
------------ ------------- ------------- ---------------
Cash flows from financing activities:
Increase in notes payable 13,750 13,750 - -
Repayment of notes payable (16,750) (16,750) - -
Increase in intercompany notes payable 5,459 5,459 - 5,459
Principal payments on capital lease obligations (253) (253) - -
Deferred loan fees paid (796) (796) - -
------------ ------------- ------------- ---------------
1,410 1,410 - 5,459
------------ ------------- ------------- ---------------
Net increase in cash and cash equivalents 169 173 1 -
Cash and cash equivalents, beginning of year 2,549 2,563 5 6
------------ ------------- ------------- ---------------
Cash and cash equivalents, end of year $ 2,718 $ 2,736 $ 6 $ 6
============ ============= ============= ===============
Supplemental disclosure of cash flow information:
Cash paid during the year for interest $ 1,960 $ 1,960 $ - $ -
Supplemental disclosure of noncash investing and
financing activities:
Capital lease asset additions $ 51 $ 51 $ - $ -
Increase in accounts payable for deferred loan fees to be
paid on future periods $ 50 $ 50 $ - $ -
Capital contributions received in exchange for accounts
payable and other noncurrent liabilities $ 5,469 $ - $ - $ -
Intercompany capital contributions $ - $ 1,723 $ 3,746 $ 1,668
See accompanying notes to the financial statements.
F2-10
BRIGHAM EXPLORATION COMPANY SUBSIDIARIES
STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 1998
(in thousands)
Brigham Brigham Brigham
Oil & Brigham, Holdings Holdings
Gas, L.P. Inc. I, LLC II, LLC
Cash flows from operating activities:
Net loss $ (34,089) $ (5,661) $ (23,362) $ (10,408)
Adjustments to reconcile net loss to cash
provided by operating activities:
Depletion of natural gas and oil properties 8,483 8,483 - -
Depreciation and amortization 413 413 - -
Capitalized ceiling impairment 25,926 25,926 - -
Amortization of stock compensation 372 372 - -
Amortization of deferred loan fees and debt issuance costs 593 593 - -
Minority interest in net loss - (23,351) - -
Equity in net loss of investee - - 23,351 8,690
Changes in working capital and other items:
Increase in accounts receivable (3,029) (3,029) - -
Increase in prepaid expenses (10) (10) - -
Increase in accounts payable 7,991 7,991 - -
Increase in participant advances received 275 275 - -
Increase in other current liabilities 862 862 - -
Decrease in deferred income tax liability - (5,088) - -
Increase in intercompany accounts payable - - - 1,707
Other noncurrent assets 6 6 - -
Other noncurrent liabilities 7,004 7,004 - -
------------- ------------- --------------- ------------
14,797 14,786 (11) (11)
------------- ------------- --------------- ------------
Cash flows from investing activities:
Natural gas and oil properties (85,208) (85,208) - -
Other property and equipment (868) (868) - -
Investment in subsidiaries and intercompany advances (42) (17) (5,154) (42,285)
Change in drilling advances paid (153) (153) - -
------------- ------------- --------------- ------------
(86,271) (86,246) (5,154) (42,285)
------------- ------------- --------------- ------------
Cash flows from financing activities:
Capital contribution received 7,548 7,548 5,170 2,302
Increase in intercompany notes payable 40,000 40,000 - 40,000
Increase in notes payable 105,800 105,800 - -
Repayment of notes payable (78,800) (78,800) - -
Principal payments on capital lease obligations (236) (236) - -
Deferred loan fees (1,990) (1,990) - -
------------- ------------- --------------- ------------
72,322 72,322 5,170 42,302
------------- ------------- --------------- ------------
Net increase in cash and cash equivalents 848 862 5 6
Cash and cash equivalents, beginning of year 1,701 1,701 - -
------------- ------------- --------------- ------------
Cash and cash equivalents, end of year $ 2,549 $ 2,563 $ 5 $ 6
============= ============= =============== ============
Supplemental disclosure of cash flow information:
Cash paid during the year for interest $ 4,878 $ 4,878 $ - $ -
Supplemental disclosure of noncash investing
and financing activities:
Capital lease asset additions $ 320 $ 320 $ - $ -
Intercompany capital contributions $ - $ - $ 29,911 $ 13,318
See accompanying notes to the financial statements.
F2-11
BRIGHAM EXPLORATION COMPANY SUBSIDIARIES
STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 1997
(in thousands)
Brigham
Oil & Brigham,
Gas, L.P. Inc.
Cash flows from operating activities:
Net income (loss) $ 69 $ (5,066)
Adjustments to reconcile net income (loss) to cash
provided by operating activities:
Depletion of natural gas and oil properties 2,743 2,743
Depreciation and amortization 306 306
Amortization of stock compensation 388 388
Minority interest in net income - 47
Changes in working capital and other items:
Increase in accounts receivable (2,213) (2,213)
Increase in prepaid expenses (128) (128)
Increase in accounts payable 8,955 8,955
Decrease in participant advances received (648) (648)
Increase in other current liabilities 50 50
Increase in deferred interest payable - related party 53 53
Increase in deferred income tax liability - 5,088
Other noncurrent assets 281 281
Other noncurrent liabilities (50) (50)
----------- --------------
9,806 9,806
----------- --------------
Cash flows from investing activities:
Natural gas and oil properties (57,170) (57,170)
Proceeds from the sale of natural gas and oil properties 74 74
Other property and equipment (545) (545)
Change in drilling advances paid 341 341
----------- --------------
(57,300) (57,300)
----------- --------------
Cash flows from financing activities:
Capital contribution received 23,927 23,927
Increase in notes payable 37,250 37,250
Repayment of notes payable (13,250) (13,250)
Principal payments on capital lease obligations (179) (179)
----------- --------------
47,748 47,748
----------- --------------
Net increase in cash and cash equivalents 254 254
Cash and cash equivalents, beginning of year 1,447 1,447
----------- --------------
Cash and cash equivalents, end of year $ 1,701 $ 1,701
=========== ==============
Supplemental disclosure of cash flow information:
Cash paid during the year for interest $ 1,679 $ 1,679
Supplemental disclosure of noncash investing and
financing activities:
Capital lease asset additions $ 403 $ 403
Intercompany capital contributions $ 16,425 $ -
Increase resulting from the Exchange and the Offering
in ownership interest in the Partnership $ - $ 13,703
See accompanying notes to the financial statements.
F2-12
BRIGHAM EXPLORATION COMPANY SUBSIDIARIES
NOTES TO THE FINANCIAL STATEMENTS
1. Organization and Background
In August 1998, upon the filing of a registration statement with the SEC,
Brigham Exploration Company, a Delaware corporation, (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"). The Notes are fully and
unconditionally guaranteed, on a joint and several basis, by each of the
Company's directly or indirectly wholly-owned subsidiaries which are Brigham Oil
& Gas, L.P. (the "Partnership"), Brigham Inc., Brigham Holdings I LLC ("Holdings
I"), and Brigham Holdings II LLC ("Holdings II"). Furthermore, these
subsidiaries have pledged their respective stock and partnership interests as
collateral for the Notes. These financial statements include the financial
statements for the wholly owned subsidiaries whose securities and partnership
interests comprise substantially all of the collateral pledged for the Notes.
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. Brigham, Inc. is a Nevada
corporation whose only asset prior to the Exchange was its less than 1%
ownership interest in the Partnership. Brigham, Inc. is the managing general
partner of the Partnership.
On February 25, 1997, the Company was formed for the purpose of exchanging
its common stock for the common stock of Brigham, Inc. and the partnership
interests of the Partnership.
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. 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. As a result of
the Exchange and the Offering, the Company owns a 68.5% partnership interest in
the Partnership and all of the outstanding shares of Brigham, Inc. Brigham, Inc.
owns the remainder of the Partnership interest in the Partnership. The proceeds
of the Offering were contributed to the Partnership by the Company.
Subsequent to the Exchange and the Offering, the Company owned a 68.5%
interest in the Partnership and Brigham, Inc. owned a 31.50% interest in the
Partnership. Effective January 1, 1998, Brigham, Inc. contributed 30.5% of its
31.5% interest in the Partnership to Holdings II, a newly formed Nevada LLC and
wholly owned subsidiary of Brigham, Inc., whose only asset is its investment in
the Partnership. Also effective January 1, 1998 the Company contributed its
68.5% interest in the Partnership to Brigham Holdings I, a newly formed Nevada
LLC and wholly owned subsidiary of the Company whose only asset is its
investment in the Partnership.
F2-13
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.
Principles of Consolidation
The accompanying financial statements include the accounts of the
Partnership, Brigham, Inc., Holdings I and Holdings II (collectively referred to
as the "Subsidiaries"). Holdings II accounts for its interest in the Partnership
under the equity method. Brigham, Inc. consolidates its interests in the
Partnership and Holdings II as a result of its general partner interest in the
Partnership and its 100% ownership of Holdings II. Holdings I accounts for its
68.5% investment in the Partnership under the equity method and its ownership in
the Partnership is reflected as the minority interest in the consolidated
results of Brigham, Inc. All entities are either directly or indirectly
wholly-owned subsidiaries of the Company. All significant intercompany accounts
and transactions have been eliminated.
Substantially all of the Subsidiaries' assets are held by and all
operations conducted through the Partnership and its subsidiaries. All
references in these financial statements to assets held by the Partnership and
transactions entered into by the Partnership are applicable to Brigham, Inc.
through its consolidation of the Partnership.
Cash and Cash Equivalents
The Subsidiaries consider all highly liquid financial instruments with an
original maturity of three months or less to be cash equivalents.
Property and Equipment
All natural gas and oil properties are held by the Partnership which 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 and administrative activities are expensed in the period incurred.
The capitalized costs of the Partnership'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 Partnership'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 Partnership 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.
F2-14
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
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 Partnership recognizes natural gas and oil sales from its interests in
producing wells under the sales method of accounting. Under the sales method,
the Partnership recognizes revenues based on the amount of natural gas or oil
sold to purchasers, which may differ from the amounts to which the Partnership
is entitled based on its interest in the properties. Gas balancing obligations
as of December 31, 1999, 1998 and 1997 were not significant. Interest is
capitalized on significant unevaluated natural gas and oil properties that are
not subject to amortization.
Industry participants in the Partnership's seismic programs are charged on
an hourly basis for the work performed by the Partnership on its 3-D seismic
interpretation workstations. The Partnership recognizes workstation revenue as
service is provided.
Derivative Instruments
The Partnership periodically enters into commodity hedge contracts,
including price swaps, caps and/or floors, 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 underlying volumes. The notional amounts of these derivative
financial instruments are based on expected production from existing wells. The
Partnership uses these derivative financial instruments to manage market risks
resulting from fluctuations in commodity prices.
Correlation of the hedge contracts is determined by evaluating whether
hedge contract gains and losses will substantially offset the effects of price
changes on the underlying natural gas and crude oil sales volumes. To the extent
that correlation exists between the hedge contracts and the underlying natural
gas and crude oil sales volumes, realized gains or losses and related cash flows
arising from the hedge contracts are recognized as a component of natural gas
and oil sales in the same period as the sale of the underlying volumes. To the
extent that correlation does not exist between the hedge contracts and the
underlying natural gas and crude oil sales volumes, realized gains or losses and
related cash flows arising from the hedge contracts are recognized in the period
incurred as a component of other income. The fair market value of any hedge
contract that does not meet the correlation test outlined above is recorded as a
deferred gain or loss on the balance sheet and is adjusted to current market
value at each balance sheet date with any deferred gains or losses recognized as
a component of other income.
F2-15
In the event that management decides to terminate a hedge contract,
generally accepted accounting principles require that any gains or losses upon
termination be carried forward and recognized as a component of natural gas and
oil sales in the period in which the underlying volumes are sold.
Federal and State Income Taxes
The Subsidiaries other than Brigham, Inc. are not taxable entities and as a
result, no income tax provision has been recorded. However, the taxable income
or loss resulting from their operations will ultimately be included in the
federal and state income tax returns of the Company and may vary substantially
from the income or loss reported for financial reporting purposes.
Brigham, Inc., which is included in the Company's consolidated income tax
return, is subject to federal corporate income taxation and utilizes an asset
and liability approach for accounting for income taxes that requires the
recognition of deferred tax assets and liabilities for the expected future tax
consequences of temporary differences between the carrying amounts and tax bases
of assets and liabilities. Resulting tax liabilities, if any, are borne by the
Company.
Segment Information
All of the Partnership's natural gas and oil properties and related
operations are located in the United States and management has determined that
the Subsidiaries have one reportable segment.
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 Partnership 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 Partnership 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 Partnership must adopt SFAS No. 133 effective
January 1, 2000. The Partnership is in the process of analyzing the potential
impact of this standard on its financial statement presentation.
F2-16
3. Asset Dispositions
In February 1999, the Partnership 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 Partnership
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 Partnership 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 Partnership 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 Partnership has certain rights to back-in for up to a 94% effective working
interest in the Duke LLC properties.
In June 1999, the Partnership sold its entire interest in certain producing
and non-producing natural gas and oil properties located in its Anadarko Basin
province to two parties for a combined sales price of $17.1 million. Total
proceeds, net of transaction costs, were $16.7 million and were used to repay a
portion of the Partnership's notes payable. Due to the magnitude of the reserve
volumes that were attributable to these properties relative to the Partnership's
remaining net reserve volumes, the Partnership recognized a loss of $12.2
million, which was difference between the sales price received, after adjustment
for transaction costs, and the $28.9 million basis allocated to the divested
properties in accordance with the full-cost method of accounting for oil and gas
properties.
4. Property and Equipment
Property and equipment (held by the Partnership), at cost, are summarized
as follows (in thousands):
December 31,
------------------------------
1999 1998
------------- --------------
Natural gas and oil properties.......................... $ 178,755 $ 181,019
Accumulated depletion................................... (66,689) (46,702)
------------- --------------
112,066 134,317
------------- --------------
Other property and equipment:
3-D seismic interpretation workstations and software. 2,248 2,186
Office furniture and equipment....................... 1,909 1,774
Accumulated depreciation............................. (2,471) (1,946)
------------- --------------
1,686 2,014
------------- --------------
$ 113,752 $ 136,331
============= ==============
At December 31, 1998, a capitalized ceiling impairment of $25.9 million was
recognized by the Partnership and is included above in the accumulated depletion
balances for natural gas and oil properties. 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.
The Partnership 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. During the years ended December 31, 1999, 1998
and 1997, these capitalized costs amounted to $3.3 million, $4.6 million and
$3.5 million, respectively. Capitalized costs do not include any costs related
to production, general corporate overhead, or similar activities. Interest costs
of $3.0 million and $1.2 million were capitalized in 1999 and 1998,
respectively.
F2-17
5. Notes Payable and Senior Subordinated Notes Payable
In January 1998, the Partnership entered into a reserve-based revolving
credit facility (the "Credit Facility") which originally provided for initial
borrowing availability of $75 million. 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 accrued interest at either the lender's Base Rate or
LIBOR plus 2.25%, at the Partnership'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 was amended in March 1999 to reduce the borrowing
availability, extend the date of borrowing base redetermination, modify certain
financial covenants, include certain additional covenants that place significant
restrictions on the Partnership's ability to make certain capital expenditures,
and to change the interest rate on outstanding borrowings to either the lender's
Base Rate or LIBOR plus 3.0%, at the Partnership's option. The Partnership
incurred a $500,000 transaction fee due to the lender over a ten month period.
In July 1999, the Credit Facility was amended to provide the Partnership
with borrowing availability of $56 million. As consideration for this amendment,
in July 1999 the Company issued to its senior lenders one million warrants to
purchase the Company's common stock at an exercise price of $2.25 per share. An
estimated value of $1.2 million was attributed to these warrants by the
Partnership and was recognized as additional deferred loan fees to be amortized
over the remaining period to maturity of the Credit Facility. The Partnership's
obligations under the Credit Facility are secured by substantially all of the
natural gas and oil properties and other tangible assets of the Partnership.
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.
Principal outstanding under the Notes is due at maturity on August 20,
2003. Interest on the 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 Notes. Interest is payable in cash at interest rates of 12%, 13%,
and 14% during the years one through three, year four and year five,
respectively, of the term of the Notes; provided, however, that the Company may
pay interest in kind for a cumulative total of seven (or potentially eight)
quarterly interest payments at interest rates of 13%, 14% and 15% during the
years one through three, year four and year five, respectively, of the term of
the Notes. 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 Subsidiaries, all of which are directly or indirectly
wholly-owned by the Company. The obligations of the Subsidiaries under the
subsidiary guaranty agreements are subordinated to the senior indebtedness of
the Partnership. Furthermore, all Subsidiaries have pledged their respective
stock and Partnership interests as collateral for the Notes.
F2-18
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.
The $40 million in proceeds from the Notes and Warrants, and subsequent
changes to the Note balance due to interest paid in kind were transferred
through a series of intercompany notes from the Company to Brigham Inc.; from
Brigham, Inc. to Holdings II; and from Holdings II to the Partnership. Principal
on the intercompany notes is due at the maturity of the Notes and intercompany
interest accrues at rates corresponding to those applicable to the Notes. In
1998, approximately $7.6 million of the proceeds from the common stock was
transferred through a series of intercompany capital contributions from the
Company to Holdings I ($5.2 million) and Brigham, Inc. ($2.4 million); from
Holdings I to the Partnership ($5.2 million); from Brigham, Inc. to Holdings II
($2.3 million) and the Partnership ($75,000); and from Holdings II to the
Partnership ($2.3 million).
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. The discount on the Notes was decreased by $479,000 to reflect the change
in value attributed to the Warrants as a result of the revision in the terms of
the Warrants.
6. Capital Lease Obligations
Property under capital leases held by the Partnership consists of the
following (in thousands):
December 31,
------------------------------
1999 1998
------------- --------------
3-D seismic interpretation workstations and software... $ 607 $ 620
Office furniture and equipment......................... 167 167
------------- --------------
774 787
Accumulated depreciation and amortization.............. (410) (276)
------------- --------------
$ 364 $ 511
============= ==============
F2-19
The obligations under capital leases are at fixed interest rates
ranging from 7.5% 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, 1999 are as
follows (in thousands):
2000..................................................... $ 258
2001..................................................... 115
2002..................................................... 27
--------------
Total minimum lease payments............................. 400
Estimated executory costs included in capital leases.. (25)
--------------
Net minimum lease payments............................... 375
Amounts representing interest......................... (38)
--------------
Present value of net minimum lease payments.............. 337
Less: current portion................................... (210)
--------------
Noncurrent portion....................................... $ 127
==============
7. Income Taxes
The provision for income taxes consists of the following (in thousands):
Year ended
December 31,
----------------------------
1999 1998
------------ ------------
Current income taxes:
Federal.................... $ - $ -
State...................... - -
Deferred income taxes:
Federal.................... - (5,088)
State...................... - -
------------ ------------
$ - $ (5,088)
============ ============
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):
Year ended
December 31,
----------------------------
1999 1998
------------ ------------
Tax at statutory rate........... $ (2,281) $ (3,655)
Add (deduct) the effect of:
Tax effect of Exchange...... - (1,433)
Valuation reserve........... 2,281 -
------------ ------------
$ - $ (5,088)
============ ============
F2-20
The components of deferred income tax assets and liabilities are as
follows (in thousands):
December 31,
-----------------------------
1999 1998
------------- -------------
Deferred tax assets:
Net operating loss carryforwards..... $ 8,119 $ 4,767
Deferred tax liability:
Depreciable and depletable property.. (7,158) (4,767)
Valuation reserve.................... (961) -
------------- -------------
$ - $ -
============= =============
At December 31, 1999, Brigham, Inc. had regular and alternative minimum tax
net operating loss carryforwards of approximately $23.2 million and $20.4
million, respectively, which expire by December 31, 2019.
8. Contingencies, Commitments and Factors Which May Affect Future Operations
Litigation
The Subsidiaries are, 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 Subsidiaries.
As of December 31, 1999, there were no known environmental or other
regulatory matters related to the Subsidiaries' operations which are reasonably
expected to result in a material liability to the Subsidiaries. Compliance with
environmental laws and regulations has not had, and is not expected to have, a
material adverse effect on their capital expenditures, earnings or competitive
position.
Lease Commitments
The Partnership 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, 1999, are
as follows (in thousands):
2000...................................................... $ 795
2001...................................................... 790
2002...................................................... 395
-------------
$ 1,980
=============
Rental expense for the years ended December 31, 1999, 1998 and 1997 was
$937,669, $875,150 and $606,173, respectively.
Major Customers
During 1999, approximately 26%, 16% and 11% of the Partnership's natural
gas and oil production was sold to three separate customers. During 1998,
approximately 25%, 15%, 11% and 11% of the Partnership's natural gas and oil
production was sold to four separate customers. During 1997, approximately 14%
and 12% of the Partnership's natural gas and oil production was sold to two
separate customers. However, due to the availability of other customers, the
Partnership does not believe that the loss of any one of these individual
customers would adversely affect the Partnership's result of operations.
F2-21
Factors Which May Affect Future Operations
Since the Partnership's major products are commodities, significant changes
in the prices of natural gas and oil could have a significant impact on the
Partnership's results of operations for any particular year.
9. Financial Instruments
The Partnership 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 Partnership 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.
In 1997, the Partnership 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. In February 1998, the Partnership 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 Partnership 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.
In August 1998, the Partnership 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 Partnership exchanges a floating market price
for a fixed contract price of $2.015 per MMBtu. Payments are made by the
Partnership 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 Partnership 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 Partnership 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.
As a result of these arrangements, the Partnership realized an increase
(decrease) in natural gas and oil revenues of approximately $(486,000), $555,000
and $(6,200) during 1999, 1998 and 1997, respectively. To the extent that
notional amounts covered by these arrangements exceed actual production
quantities, a corresponding portion of the contracts has been recorded on the
balance sheet at fair value, which approximated $291,000 as of December 31,
1999. Additionally, the mark-to-market adjustments and related cash flows
associated with this portion of the contract of approximately $(429,000) have
been recorded as a component of other income (expense) on the 1999 statement of
operations.
F2-22
In September 1999, the Partnership amended the fixed contract price from
$2.065 per MMBtu to a range from $2.509 to $2.678 per MMBtu for natural gas
volumes for the months of October 1999 through January 2000 under the then
outstanding swap agreement. This resulted in a deferred loss of $1.1 million to
be amortized to natural gas and oil revenues over the original contract period
of October 1999 through January 2000. During 1999, approximately $645,000 was
amortized to natural gas and oil revenues.
Concurrently, in September 1999 the Partnership entered into natural gas
and crude oil cap contracts. The natural gas cap contract provides the
counterparty with a call option on 10,000 MMBtu per day of natural gas
production for the monthly periods from May 2001 through June 2002. Payments are
made by the Partnership to the counterparty when the floating price exceeds the
fixed price of $2.50 per MMBtu for the periods May 2001 through October 2001 and
May 2002 through June 2002, and $2.70 per MMBtu for the period November 2001
through April 2002.
These instruments do not qualify for hedge accounting and accordingly were
recorded on the date of the transaction at their fair value of $1.1 million as a
deferred credit on the balance sheet. As of December 31, 1999, the fair value of
the remaining contracts approximated $875,000 million with the corresponding
mark-to-market adjustments and related cash flows recorded as a component of
other income (expense) on the statement of operations.
The Partnership'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 Partnership's revolving credit facility approximates
its fair market value since it bears interest at floating market interest rates.
The Partnership's accounts receivable relate to natural gas and oil sales
to various industry companies, amounts due from industry participants for
expenditures made by the Partnership on their behalf and workstation revenues.
Credit terms, typical of industry standards, are of a short-term nature and the
Partnership does not require collateral. The Partnership's accounts receivable
at December 31, 1999 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.
10. Employee Benefit Plans
Retirement Savings Plan
The Partnership has adopted a defined contribution 401(k) plan for
substantially all of its employees. In 1997 Brigham, Inc. succeeded to the
401(k) plan when the employees of the Partnership became employees of Brigham,
Inc. Eligible employees may contribute up to 15% of their compensation to this
plan. The 401(k) plan provides that the employer may, at its discretion, match
employee contributions. The employer has not matched employee contributions in
any plan year.
F2-23
Stock Compensation
In 1994 three employees were granted restricted interests in the
Partnership 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 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. 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.
Non-cash compensation expense related to certain stock options granted under the
incentive plan by the Company on behalf of the Partnership has been allocated to
the Partnerships's results of operations. Compensation expense allocated to the
Partnership totaled $600,506, $782,544 and $833,710 in 1999, 1998 and 1997,
respectively.
11. Subsequent Event
In February 2000, the Partnership entered into an amended and restated
Credit Facility with its existing lenders and a new lender. This amended and
restated Credit Facility provides the Partnership with an increase to $70
million in borrowing availability for a three-year term. If the Partnership
exceeds certain asset value and interest coverage tests in the second or third
quarters of 2000, the total borrowing availability under the Credit Facility
will increase to $75 million. Borrowings under the Credit Facility in excess of
$45 million are convertible into shares of the Company's common stock in the
following amounts: (i) the first $10 million of borrowings is convertible at
$3.90 per share, (ii) the second $10 million is convertible at $6.00 per share,
and (iii) the final $10 million is convertible at $8.00 per share. If the Credit
Facility is repaid at maturity or is prepaid prior to maturity without payment
of cash premiums, the Company must issue to a new lender of the Credit Facility
warrants to purchase shares of the Company's common stock. In addition, certain
financial covenants of the Credit Facility have been amended or added. In
connection with this most recent amendment, the Company reset the price of the
warrants previously issued to its existing senior lenders to purchase one
million shares of the Company's common stock from an exercise price of $2.25 per
share to $2.02 per share.
In February 2000, the indenture governing the Notes was amended. The
holders of the Notes waived the minimum consolidated interest coverage ratio
covenant through June 30, 2000 and adjusted subsequent levels under this test.
In addition, an amendment to the Notes provides the Company with an extension of
its right to pay interest through the issuance of additional Notes in lieu of
cash (or "in kind") through the third quarter of 2000 and potentially through
the fourth quarter of 2000 if certain conditions are met. In exchange for
granting these amendments, the Company has (i) reset the price of the warrants
previously issued to the holders of the Notes to purchase one million shares of
the Company's common stock from an exercise price of $3.50 per share to $2.43
per share and (ii) granted to the holders of the Notes a term overriding royalty
interest that provides for the limited right to receive 4%, or 3% if certain
conditions are met, of the Company's net production revenue to reduce any
outstanding Notes issued as interest paid in kind.
F2-24
12. 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." All natural gas and oil
properties are held by the Partnership.
The Partnership's natural gas and oil properties are included in the
consolidated results of Brigham, Inc., subject to the minority interest of 68.5%
held by the Company in 1997 and by Holdings I in 1999 and 1998.
Results of Operations for Natural Gas and Oil Producing Activities
(in thousands)
Year ended December 31,
-------------------------------------
1999(a) 1998(a) 1997(a)
----------- ------------ ----------
Natural gas and oil sales........................................... $ 14,992 $ 13,799 $ 9,184
Costs and expenses:
Lease operating................................................. 2,259 2,172 1,151
Production taxes................................................ 968 850 549
Depletion of natural gas and oil properties..................... 7,792 8,483 2,743
Capitalized ceiling impairment.................................. - 25,926 -
----------- ------------ ----------
Total costs and expenses........................................... 11,019 37,431 4,443
----------- ------------ ----------
$ 3,973 $ (23,632) $ 4,741
=========== ============ ==========
Depletion per physical unit of production (equivalent Mcf of gas).. $ 1.24 $ 1.27 $ 0.88
=========== ============ ==========
- -----------------
(a) The income tax expense (benefit) related to Brigham, Inc. for 1998,
1998 and 1997 is calculated at the statutory rate and determined
without regard to deduction for general and administrative expenses,
interest costs and other income tax deductions and credits. Upon
consolidation of the Partnership interest into Brigham, Inc. for
1999, 1998 and 1997, the income tax expense (benefit) related to
results of operations for natural gas and oil producing activities
for Brigham, Inc. would be $438, $(2,605) and $523, respectively.
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. 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.
F2-25
Costs Incurred and Capitalized Costs
The costs incurred in natural gas and oil acquisition, exploration and
development activities follow (in thousands):
December 31,
----------------------------------------
1999 1998 1997
------------ ------------ ------------
Costs incurred for the year:
Exploration................. $ 19,224 $ 68,214 $ 29,516
Property acquisition........ 3,462 16,245 26,956
Development................. 4,632 10,475 2,953
Proceeds from participants.. (2,439) (10,502) (319)
------------ ------------ ------------
$ 24,879 $ 84,432 $ 59,106
============ ============ ============
Costs incurred represent amounts incurred by the Partnership for
exploration, property acquisition and development activities. Periodically, the
Partnership 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,
------------------------------
1999 1998
------------- --------------
Cost of natural gas and oil properties at year-end:
Proved............................................. $ 140,757 $ 128,643
Unproved........................................... 37,998 52,376
------------- --------------
Total capitalized costs............................ 178,755 181,019
Accumulated depletion.............................. (66,689) (46,702)
------------- --------------
$ 112,066 $ 134,317
============= ==============
Following is a summary of costs (in thousands) excluded from depletion at
December 31, 1999, by year incurred. At this time, the Partnership 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
------------------------------------
1999 1998 1997 Years Total
----------- ----------- ---------- ---------- ----------
Property acquisition........................ $ 1,079 $ 6,414 $ 5,558 $ 1,921 $ 14,972
Exploration................................. 1,174 12,876 7,404 1,572 23,026
----------- ----------- ---------- ---------- ----------
Total....................................... $ 2,253 $ 19,290 $ 12,962 $ 3,493 $ 37,998
=========== =========== ========== ========== ==========
13. Natural Gas and Oil Reserves and Related Financial Data (Unaudited)
Information with respect to the Partnership'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 Partnership's independent petroleum consultants and internal
petroleum reservoir engineer.
F2-26
Natural Gas and Oil Reserve Data
The following tables present the Partnership's estimates of its proved
natural gas and oil reserves. The Partnership 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.
Natural
Gas Oil
(MMcf) (MBbls)
------------- --------------
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 to 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
Revisions of previous estimates.................... (9,938) 214
Extensions, discoveries and other additions........ 30,428 1,156
Sales of minerals-in-place......................... (22,002) (2,430)
Production......................................... (4,197) (346)
------------- --------------
Proved reserves at December 31, 1999.................. 65,457 3,027
============= ==============
Proved developed reserves at December 31:
1997............................................... 30,677 2,665
1998............................................... 38,571 2,935
1999............................................... 28,594 1,873
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.
F2-27
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 Partnership'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 Partnership's natural gas and oil reserves.
December 31,
----------------------------------------
1999 1998 1997
------------ ------------ ------------
Future cash inflows............................................. $ 228,429 $ 198,082 $ 165,156
Future development and production costs......................... (61,878) (61,064) (40,923)
------------ ------------ ------------
Future net cash inflows......................................... $ 166,551 $ 137,018 $ 124,233
============ ============ ============
Standardized measure of future net cash inflows discounted
at 10% per annum............................................. $ 114,466 $ 81,741 $ 69,249
============ ============ ============
Estimated future income tax expense as of December 31, 1999, 1998 and 1997
attributable to Brigham, Inc.'s interest in the Partnership was $3.9 million,
$2.2 million and $7.2 million, respectively. The standardized measure of future
net cash inflows discounted at 10% per annum as of December 31, 1999, 1998 and
1997 after estimated income taxes attributable to Brigham, Inc.'s interest in
the Partnership was $114.2 million, $81.7 million and $67.7 million,
respectively.
The base sales prices for the Partnership's reserves were $2.35 per Mcf for
natural gas and $22.75 per Bbl for oil as of December 31, 1999, $2.12 per Mcf
for natural gas and $9.50 per Bbl for oil as of December 31, 1998, and $2.27 per
Mcf for natural gas and $15.50 per Bbl for oil as of December 31, 1997. 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 Partnership's reserves at these dates.
F2-28
Changes in the future net cash inflows discounted at 10% per annum
follow (in thousands):
December 31,
----------------------------------------
1999 1998 1997
------------ ------------ ------------
Beginning of period ....................................... $ 81,741 $ 69,249 $ 44,506
Sales of natural gas and oil produced, net of production
costs ............................................. (11,765) (10,776) (7,484)
Development costs incurred ............................. 4,413 5,423 1,955
Extensions and discoveries ............................. 43,346 52,389 38,016
Purchases of minerals-in-place ......................... -- 687 16,965
Sales of minerals-in-place ............................. (32,783) -- (94)
Net change of prices and production costs .............. 33,226 (11,921) (20,466)
Change in future development costs ..................... (555) (656) 319
Changes in production rates and other .................. 637 (6,109) (1,954)
Revisions of quantity estimates ........................ (11,969) (23,470) (6,964)
Accretion of discount .................................. 8,174 6,925 4,450
--------- --------- ---------
End of period ............................................. $ 114,465 $ 81,741 $ 69,249
========= ========= =========
The estimated change in future net cash inflows discounted at 10% per annum
attributable to income taxes for the years ended December 31, 1999, 1998 and
1997 attributable to Brigham, Inc.'s interest in the Partnership was $(261,000),
$1.5 million and $(1.6) million, respectively.
14. Quarterly Financial Data (Unaudited)
The Subsidiaries have restated previously reported quarterly financial
results for the nine months ended September 30, 1999 and the year ended December
31, 1998 to give effect to the capitalization of interest for significant
acquisition, exploration and development activities in progress. There was no
effect on the year ended December 31, 1998 net loss or on the 1997 financial
results. The effect of this restatement on the statement of operations is as
follows (in thousands):
Year Ended December 31, 1999
------------------------------------------------------------------------------------
Quarter 1 Quarter 2 Quarter 3 Quarter 4
------------------------ ---------------------- ----------------------- ------------
Previously As Previously As Previously As
Reported Restated Reported Restated Reported Restated
------------- ---------- ------------ --------- ------------ ----------
Brigham Oil and Gas, L.P.
Revenue........................... $ 3,281 $ 3,281 $ 3,626 $ 3,624 $ 4,195 $ 4,238 $ 4,134
Operating income (loss)........... 124 113 255 200 (379) (432) 389
Net loss.......................... (2,484) (1,759) (14,794) (14,599) (3,329) (2,391) (1,909)
Brigham, Inc.
Revenue........................... $ 3,281 $ 3,281 $ 3,626 $ 3,624 $ 4,195 $ 4,238 $ 4,134
Operating income (loss)........... 124 113 250 195 (379) (432) 384
Net loss.......................... (783) (554) (4,664) (4,604) (1,049) (753) (606)
Brigham Holdings I, LLC
Revenue........................... $ - $ - $ - $ - $ - $ - $ -
Operating income (loss)........... - - (5) (5) - - (4)
Net loss.......................... (1,701) (1,205) (10,140) (10,005) (2,280) (1,638) (1,312)
Brigham Holdings II, LLC
Revenue........................... $ - $ - $ - $ - $ - $ - $ -
Operating income (loss)........... - - (5) (5) - - (4)
Net loss.......................... (758) (537) (4,517) (4,457) (1,015) (729) (587)
F2-29
Year Ended December 31, 1998
-----------------------------------------------------------------------------------------------
Quarter 1 Quarter 2 Quarter 3 Quarter 4
------------------------ ---------------------- ---------------------- ------------------------
Previously As Previously As Previously As Previously As
Reported Restated Reported Restated Reported Restated Reported Restated
------------- ---------- ----------- ---------- ----------- --------- ---------- --------------
Brigham Oil & Gas, L.P.
Revenue.................$ 3,257 $ 3,257 $ 4,120 $ 4,120 $ 4,237 $ 4,237 $ 2,575 $ 2,575
Operating income (loss). 31 27 438 424 481 466 (28,475) (29,594)
Net loss................ (954) (692) (932) (682) (1,348) (1,064) (30,855) (31,651)
Brigham, Inc.
Revenue.................$ 3,257 $ 3,257 $ 4,120 $ 4,120 $ 4,237 $ 4,237 $ 2,575 $ 2,575
Operating income (loss). 31 27 432 418 481 466 (28,480) (29,599)
Net loss................ (207) (152) (201) (150) (280) (221) (4,973) (5,138)
Brigham Holdings I, LLC
Revenue.................$ - $ - $ - $ - $ - $ - $ - $ -
Operating income (loss). - - (6) (6) - - (5) (5)
Net loss................ (653) (474) (645) (473) (923) (729) (21,141) (21,686)
Brigham Holdings II, LLC
Revenue.................$ - $ - $ - $ - $ - $ - $ - $ -
Operating income (loss). - - (6) (6) - - (5) (5)
Net loss................ (291) (211) (290) (214) (411) (325) (9,416) (9,658)
F2-30