<PAGE> 1
Filed Pursuant to Rule 424(b)(4)
Registration No. 333-22491
PROSPECTUS
3,000,000 SHARES
[BRIGHAM EXPLORATION COMPANY LOGO]
COMMON STOCK
The 3,000,000 shares of common stock, par value $.01 per share (the "Common
Stock"), offered hereby are being sold by Brigham Exploration Company ("Brigham"
or the "Company"). Prior to the offering made hereby (the "Offering"), there has
been no public market for the Common Stock. See "Underwriting" for information
relating to the factors considered in determining the initial public offering
price. The Common Stock has been approved for listing on the Nasdaq National
Market under the symbol "BEXP."
------------------------------
ANY INVESTMENT IN THE SECURITIES OFFERED HEREIN INVOLVES A HIGH DEGREE OF
RISK. SEE "RISK FACTORS" BEGINNING ON PAGE 10.
------------------------------
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE
ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
<TABLE>
<CAPTION>
==============================================================================================================
UNDERWRITING
PRICE TO DISCOUNTS AND PROCEEDS TO
PUBLIC COMMISSIONS(1) COMPANY(2)
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Per Share...................................... $8.00 $0.56 $7.44
- --------------------------------------------------------------------------------------------------------------
Total(3)....................................... $24,000,000 $1,680,000 $22,320,000
==============================================================================================================
</TABLE>
(1) The Company and the Selling Stockholders named herein have agreed to
indemnify the Underwriters against certain liabilities, including
liabilities under the Securities Act of 1933. See "Underwriting."
(2) Before deducting expenses of the Offering payable by the Company estimated
at $750,000.
(3) The Company and the Selling Stockholders have granted the Underwriters a
30-day option to purchase up to 450,000 additional shares of Common Stock on
the same terms and conditions as set forth above to cover over-allotments,
if any. If the Underwriters exercise this option in full, the total Price to
Public will be $27,600,000, the total Underwriting Discounts and Commissions
will be $1,932,000, the total Proceeds to Company will be $24,738,000 and
the total Proceeds to Selling Stockholders will be $930,000. See
"Underwriting."
------------------------------
The shares of Common Stock are offered, subject to prior sale, when, as and
if delivered to and accepted by the Underwriters and subject to certain other
conditions. The Underwriters reserve the right to withdraw, cancel or modify
such offer and to reject orders in whole or in part. It is expected that
delivery of the shares of Common Stock will be made against payment therefor, on
or about May 14, 1997 at the offices of Bear, Stearns & Co. Inc., 245 Park
Avenue, New York, New York 10167.
------------------------------
BEAR, STEARNS & CO. INC.
HOWARD, WEIL, LABOUISSE, FRIEDRICHS
INCORPORATED
RAUSCHER PIERCE REFSNES, INC.
THE DATE OF THIS PROSPECTUS IS MAY 8, 1997
<PAGE> 2
[MAP DEPICTING BRIGHAM'S AREAS OF CORE ACTIVITY. The omitted map is
captioned "Core Exploration Provinces" and depicts Texas, Louisiana and
Oklahoma, with three areas marked to indicate the Anadarko Basin, the West Texas
Region and the Gulf Coast. Relating to the area marked Anadarko Basin, the
following information is provided: 1,043 Sq. Miles of 3-D Acquired, 942 Sq.
Miles of 3-D Interpreted, 24 Projects, 325 Potential 3-D Drilling Locations.
Relating to the area marked West Texas Region, the following information is
provided: 1,552 Sq. Miles of 3-D Acquired, 1,552 Sq. Miles of 3-D Interpreted,
73 Projects, 508 Potential 3-D Drilling Locations. Relating to the area marked
Gulf Coast, the following information is provided: 533 Sq. Miles of 3-D
Acquired, 154 Sq. Miles of 3-D Interpreted, 6 Projects, 31 Potential 3-D
Drilling Locations. Under the caption "Other", the following information, set
apart from the three-state map, is provided: 215 Sq. Miles of 3-D Acquired, 189
Sq. Miles of 3-D Interpreted, 22 Projects, 30 Potential 3-D Drilling Locations.
Beneath the map and under the caption "TOTAL," the following information is
provided: 3,343 Sq. Miles of 3-D Acquired, 2,837 Sq. Miles of 3-D Interpreted,
125 Projects, 894 Potential 3-D Drilling Locations.]
------------------------------
CERTAIN PERSONS PARTICIPATING IN THIS OFFERING MAY ENGAGE IN TRANSACTIONS
THAT STABILIZE, MAINTAIN OR OTHERWISE AFFECT THE PRICE OF THE COMMON STOCK,
INCLUDING OVER-ALLOTMENT, STABILIZING AND SHORT-COVERING TRANSACTIONS IN SUCH
COMMON STOCK, AND THE IMPOSITION OF A PENALTY BID, DURING AND AFTER THE
OFFERING. FOR A DESCRIPTION OF THESE ACTIVITIES, SEE "UNDERWRITING."
2
<PAGE> 3
PROSPECTUS SUMMARY
The following summary should be read in conjunction with, and is qualified
in its entirety by, the detailed information and the Financial Statements and
notes thereto included elsewhere in this Prospectus. All references in this
Prospectus to "Brigham" or the "Company" include Brigham Exploration Company,
its predecessors and their subsidiaries. Unless otherwise indicated, the
information in this Prospectus assumes no exercise of the Underwriters'
over-allotment option. Certain terms relating to the oil and gas industry are
defined in "Glossary of Certain Oil and Gas Terms."
THE COMPANY
Brigham is an independent exploration and production company that applies
3-D seismic imaging and other advanced technologies to systematically explore
and develop onshore domestic natural gas and oil provinces. With this focus,
Brigham has achieved rapid growth in reserves, potential drilling locations and
3-D seismic data.
Since inception in 1990, Brigham has drilled over 265 exploratory and 35
development wells on its 3-D generated prospects with an aggregate 63% success
rate. Through December 31, 1996, the Company had discovered total estimated
proved reserves of 70.1 Bcf of natural gas and 22.4 MMBbls of oil, or an
aggregate of 204.5 Bcfe, 14% of which is attributable to the Company's interest.
The Company's estimated proved reserves as of December 31, 1996 were 21.9 Bcfe
having an aggregate Present Value of Future Net Revenues of $44.5 million,
compared to estimated proved reserves as of December 31, 1993 of 2.2 Bcfe having
an aggregate Present Value of Future Net Revenues of $3.2 million.
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 natural gas and oil reserves. Brigham has acquired over
3,300 square miles (2,112,000 acres) of 3-D seismic data and, from the 2,837
square miles interpreted to date, has identified approximately 1,200 potential
drilling locations. Brigham has drilled over 300 of these locations with an
average working interest of 21%. The Company generates most of its exploratory
projects and, therefore, has the ability to retain a sizeable working interest
to the extent that it decides not to place interests with industry participants.
In the projects in which it is currently acquiring 3-D seismic data, the Company
may retain an average working interest in the drilling and leasing phases in
excess of 60%.
BUSINESS STRATEGY
Brigham was founded in 1990 with the core belief that systematic
exploration applying 3-D seismic imaging and other advanced technologies could
reduce drilling risks and finding costs. Brigham's business strategy is to
continue to increase shareholder value by focusing on this core belief.
Brigham's exploration activities are concentrated primarily in three
provinces: the Anadarko Basin, the Gulf Coast and the West Texas region. The
Company is accelerating its 3-D seismic activity in the Anadarko Basin and the
Gulf Coast and will continue such activity in those geologic trends of the West
Texas region where it has achieved its best results historically. Brigham is
focusing its 3-D seismic activity in provinces where it believes 3-D technology
may be effectively applied and that it believes offer large potential reserve
volumes per well and per field, high potential production rates and multiple
producing objectives.
The Company's growth will be driven by drilling and developing its
potential drilling locations, as well as adding new locations through its
systematic 3-D seismic exploration effort. Using the proceeds of the Offering,
Brigham plans to accelerate growth by (i) increasing the working interest it
retains in drilling locations in order to capture a greater share of the
reserves the Company discovers, (ii) increasing the rate at which it acquires
3-D seismic data and identifies potential drilling locations, (iii) seeking to
identify higher potential drilling locations, (iv) increasing the rate at which
potential drilling locations are drilled and (v) reducing the time spent
marketing projects to industry participants.
3
<PAGE> 4
COMPETITIVE ADVANTAGES
Brigham believes that its knowledge base, personnel and technology provide
it with the following competitive advantages to capture undiscovered natural gas
and oil reserves.
Pioneering Innovations. In 1990 the Company pioneered the
assemblage of large scale onshore 3-D seismic projects and the use of
preseismic lease options for the systematic exploration of proven
natural gas and oil provinces. Subsequent innovations include the
Company's 3-D seismic acquisition and processing alliances and
creative industry trade structures to financially leverage its
drilling program.
3-D Seismic Knowledge Base. Since inception, the Company has
acquired over 3,300 square miles of 3-D seismic data and drilled more
than 300 wells in over 20 geologic trends in six basins and seven
states. With the resulting knowledge of the application of 3-D seismic
to different geologic trends, the Company has refined its exploration
techniques and identified exploration areas where it believes 3-D
seismic can reduce risks and enhance returns on its investments.
Technological Expertise. Brigham's explorationists collectively
have over 200 years of experience, including over 65 years of
experience using computer aided exploration ("CAEX") workstations, and
have expertise in many geologic trends.
Project Generation and Control. Brigham is not dependent on third
parties for its project flow, having generated approximately 90% of
its 3-D exploration projects. With the resulting project control, the
Company is able to manage the predrilling exploration phases and can
determine the level of working interest it retains and the extent to
which it manages drilling and post-drilling operations.
Numerous Potential Drilling Locations. The Company has identified
approximately 1,200 3-D defined potential drilling locations in
historically productive geologic trends, of which over 300 have been
drilled. The Company anticipates drilling 91 of these locations (23.8
net) in 1997 at a cost of approximately $16.0 million.
PRIMARY EXPLORATION PROVINCES
Brigham's exploration activities are concentrated primarily in three
provinces: the Anadarko Basin, the Gulf Coast and the West Texas region. Brigham
is accelerating 3-D seismic activity in the Anadarko Basin and the Gulf Coast
and will continue such activity in those geologic trends of the West Texas
region where it has achieved its best results historically. Brigham is focusing
its 3-D seismic exploration efforts in provinces where it believes 3-D
technology may be effectively applied and that it believes offer large potential
reserve volumes per well and per field, high potential production rates and
multiple producing objectives.
Although the Company is acquiring 3-D seismic data within the provinces
listed below and has identified approximately 900 potential drilling locations
yet to be drilled in those provinces, there can be no assurance that any of the
seismic data will be acquired or will generate additional drilling locations or
that any potential drilling locations will be drilled at all or within the
expected time frame. The final determination with respect to the drilling of any
well, including those currently budgeted, will depend on a number of factors,
including (i) the results of exploration efforts and the review and analysis of
the seismic data, (ii) the availability of sufficient capital resources by the
Company and other participants for drilling prospects, (iii) economic and
industry conditions at the time of drilling, including prevailing and
anticipated prices for natural gas and oil and the availability of drilling rigs
and crews, (iv) the financial resources and results of the Company and (v) the
availability of leases on reasonable terms and permitting for the potential
drilling location. There can be no assurance that the budgeted wells will, if
drilled, encounter reservoirs of commercial quantities of natural gas or oil.
4
<PAGE> 5
<TABLE>
<CAPTION>
ADDITIONAL 3-D 1997
SEISMIC DATA ADDITIONAL BUDGETED ESTIMATED
3-D SEISMIC BUDGETED FOR TOTAL GROSS POTENTIAL WELLS 1997
DATA ACQUIRED/ ACQUISITION WELLS DRILLED DRILLING ------------ CAPITAL
PROVINCE INTERPRETED(1) IN 1997 THROUGH 1996 LOCATIONS(2) GROSS NET EXPENDITURES(3)
-------- --------------- -------------- ------------- ------------ ----- ---- ---------------
(SQUARE MILES) (SQUARE MILES) (IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
Anadarko Basin................. 1,043/942 493 31 325 41 12.3 $15,000
Gulf Coast..................... 533/154 191 1 31 7 2.2 7,000
West Texas Region.............. 1,552/1,552 68 255 508 41 8.2 4,000
Other (4)...................... 215/189 60 11 30 2 1.1 1,000
----------- --- --- --- -- ---- -------
Total.................. 3,343/2,837 812(5) 298 894 91 23.8 $27,000
=========== === === === == ==== =======
</TABLE>
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(1) 3-D seismic data that had been or was being acquired/interpreted on
February 15, 1997.
(2) The potential drilling locations that had been identified from the
portion of the 3-D seismic data that had been interpreted by February
15, 1997.
(3) 3-D seismic and land acquisition costs and drilling expenditures.
(4) Colorado, Kansas and Montana.
(5) The Company has budgeted approximately 1,400 square miles of 3-D
seismic data for acquisition in 1997, 582 of which had been acquired or
were being acquired on February 15, 1997.
Anadarko Basin. The Anadarko Basin is a prolific natural gas province that
the Company believes has been relatively under explored, particularly with
regard to deep, high potential objectives. The Anadarko Basin contains numerous
historically elusive stratigraphic targets, such as the Red Fork, Morrow and
Springer channel sands, and structural targets, such as the Hunton and Arbuckle
carbonates, which are well-suited to 3-D seismic imaging. In some cases, these
objectives have produced in excess of 30 Bcf of natural gas from a single well
at rates up to 30 MMcf of natural gas per day.
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 7,400 miles of 2-D seismic data. Working with
consulting regional geologists, the Company's explorationists integrate this
data with their expertise and knowledge base to generate 3-D projects in the
Anadarko Basin.
As of February 15, 1997, the Company had acquired 1,043 square miles
(667,520 acres) of 3-D seismic data in 24 projects in the Anadarko Basin. As of
December 31, 1996, Brigham had completed 23 wells in 31 attempts (a 74% success
rate) in this province and had found cumulative proved reserves of 53.4 Bcf of
natural gas and 1.7 MMBbls of oil, or an aggregate of 63.4 Bcfe, with 16.3%
attributable to the Company's interest. In 1996, the Company completed 14 wells
in 20 attempts, adding 38.8 Bcfe of proved reserves, with 6.7 Bcfe attributable
to the Company's interest. As of February 15, 1997, the Company had 325 3-D
delineated potential drilling locations in the Anadarko Basin, of which the
Company intends to drill 41 gross (12.3 net) wells in 1997.
Gulf Coast. The Gulf Coast is a high potential, multi-pay province that
lends itself to 3-D seismic exploration due to its substantial structural and
stratigraphic complexity. The Company has assembled a digital data base
including geographical, production, geophysical and geological information that
the Company evaluates on its CAEX workstations. Working with consulting regional
geologists the Company's explorationists integrate this data with their
expertise and knowledge base to generate 3-D projects in the Gulf Coast.
Brigham's commitment to this province is evidenced by the Company's staff
additions, the opening of its Houston office and the addition of ten new 3-D
seismic projects in 1996 and 1997.
As of February 15, 1997, the Company had acquired or was acquiring 533
square miles (341,120 acres) of 3-D seismic data in six projects in the onshore
Gulf Coast. The Company anticipates acquiring 191 square miles (122,240 acres)
of additional 3-D seismic data in 1997.
The Company anticipates that its increased project assemblage and 3-D
seismic acquisition activity in the Gulf Coast will generate accelerated
drilling in the province in 1997 and 1998. The Company is currently assembling
projects in the Expanded Wilcox, Expanded Vicksburg and Yegua trends in South
Texas, the
5
<PAGE> 6
Miocene trend in South Texas and South Louisiana, and the Lower and Middle Frio
trends of the upper Gulf Coast of Texas. The Company has thirty-one 3-D
delineated potential drilling locations in the Gulf Coast and intends to drill 7
gross (2.2 net) wells in 1997.
West Texas Region. The Company's 3-D seismic and drilling activity in the
West Texas region has been focused in the Horseshoe Atoll, the Midland Basin and
the Eastern Shelf of the Permian Basin and the Hardeman Basin. The Company plans
to continue drilling its locations in these areas. Recently the Company
increased its activity in portions of geologic trends that the Company believes
offer greater potential for lower finding costs and higher returns, including
the Ellenberger and Devonian formations of the Delaware Basin and the Fusselman
formation of the Permian Basin. One area where the Company increased its
activity is in the Midland Basin, where the Company has drilled five recent
Fusselman discoveries and has acquired or intends to acquire 3-D seismic in four
additional projects, in which it expects to retain working interests in excess
of 50%.
As of February 15, 1997, the Company had acquired 1,552 square miles
(993,280 acres) of 3-D seismic in 73 projects in the West Texas region. As of
December 31, 1996, the Company had completed 164 wells in 255 attempts (a 64%
success rate) and had found cumulative proved reserves of 16.7 Bcf of natural
gas and 20.6 MMBbls of oil, or an aggregate of 139.8 Bcfe, with 13.0%
attributable to the Company's interest. In 1996 the Company completed 28 wells
in 43 attempts in this province, adding 29.8 Bcfe of proved reserves, with 5.7
Bcfe attributable to the Company's interest. The Company has 508 3-D delineated
potential drilling locations in the West Texas region and intends to drill 41
gross (8.2 net) wells in 1997.
THE OFFERING
<TABLE>
<S> <C>
Common Stock Offered by the Company....................... 3,000,000 shares
Common Stock to be Outstanding after the Offering......... 11,928,574 shares(1)
Use of Proceeds........................................... The net proceeds of the Offering will
be used for exploration and development
activities, repayment of all
outstanding indebtedness of
approximately $13.25 million, and other
general corporate purposes. See "Use of
Proceeds."
Nasdaq National Market Symbol............................. "BEXP"
</TABLE>
- ---------------
(1) Does not include 644,097 shares of Common Stock issuable upon exercise
of outstanding employee stock options with an average exercise price of
$5.00 per share. See "Management -- Executive Compensation" and Note 3
of Notes to Balance Sheet and Note 8 of Notes to Financial Statements.
RISK FACTORS
Any investment in the Common Stock involves a high degree of risk. For a
discussion of certain risks that a potential investor should carefully evaluate
prior to making an investment in the Common Stock, see "Risk Factors."
6
<PAGE> 7
SUMMARY FINANCIAL DATA
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
The following table sets forth certain summary financial data of the
Company. The information should be read in conjunction with the Management's
Discussion and Analysis of Financial Condition and Results of Operations, the
Unaudited Pro Forma Financial Statements and notes thereto and the Financial
Statements and notes thereto included elsewhere in this Prospectus.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------
1992(1) 1993 1994 1995 1996
------- ------- ------- ------- --------
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues:
Natural gas and oil sales............... $ 244 $ 937 $ 2,565 $ 3,578 $ 6,141
Workstation revenue..................... 252 467 815 635 627
------- ------- ------- ------- --------
Total revenues..................... 496 1,404 3,380 4,213 6,768
Costs and expenses:
Lease operating......................... 32 111 491 761 726
Production taxes........................ 12 47 126 165 362
General and administrative.............. 462 1,433 1,785 1,897 2,199
Depletion of natural gas and oil
properties............................ 127 4,371(2) 1,104 1,626 2,323
Depreciation and amortization........... 224 406 561 533 487
------- ------- ------- ------- --------
Total costs and expenses........... 857 6,368 4,067 4,982 6,097
------- ------- ------- ------- --------
Operating income (loss).................... (361) (4,964) (687) (769) 671
Other income (expense):
Interest income......................... 12 6 56 128 52
Interest expense........................ (21) (105) (668) (936) (1,173)
------- ------- ------- ------- --------
Net loss................................... $ (370) $(5,063) $(1,299) $(1,577) $ (450)
======= ======= ======= ======= ========
PRO FORMA STATEMENT OF OPERATIONS DATA:
Net income(3)(4)........................... $ 69
Net income per share(3)(4)................. $ 0.01
Weighted average shares outstanding(3)..... 9,170
STATEMENT OF CASH FLOWS DATA:
Net cash provided by (used in) operating
activities.............................. $ (172) $ (730) $ 626 $ 1,383 $ 3,710
Net cash used in investing activities...... (3,931) (6,983) (5,463) (8,005) (11,796)
Net cash provided by financing
activities.............................. 4,845 7,839 4,634 7,724 7,731
OTHER FINANCIAL DATA:
Capital expenditures....................... $ 4,285 $ 6,632 $ 5,445 $ 7,935 $ 13,612
EBITDA(5).................................. 2 (181) 1,034 1,518 3,533
Cash flow from operations(6)............... (19) (286) 366 582 2,360
</TABLE>
<TABLE>
<CAPTION>
AS OF DECEMBER 31, 1996
--------------------------------------------------
PRO FORMA
ACTUAL PRO FORMA(3)(4) AS ADJUSTED(3)(4)(7)
------- --------------- --------------------
<S> <C> <C> <C>
BALANCE SHEET DATA:
Cash and cash equivalents..................... $ 1,447 $ 1,447 $15,017
Natural gas and oil properties, net........... 28,005 28,005 28,005
Total assets.................................. 33,614 33,614 47,184
Notes payable................................. 24,000 8,000 --
Total equity.................................. 3,244 14,565 36,135
</TABLE>
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- ---------------
(1) Represents the period from inception (May 1, 1992) of the Partnership,
the Company's predecessor, through December 31, 1992. Operations of the
predecessor to the Partnership for the period from January 1, 1992
through April 30, 1992 were insignificant. See "The Company."
(2) Includes a capitalized ceiling impairment of $3.3 million in 1993.
(3) Gives effect to the Exchange (see "The Company") and the issuance of
stock options to employees under the 1997 Incentive Plan as if they had
occurred on January 1, 1996 for Statement of Operations Data and as of
December 31, 1996 for Balance Sheet Data. See the Unaudited Pro Forma
Financial Statements and Note 1 of Notes to Financial Statements.
(4) Prior to the Exchange, the Company's predecessor was classified as a
partnership for federal income tax purposes. No provision has been made
for income taxes since these taxes are the responsibility of the
partners. The pro forma data reflect an income tax benefit in 1996 of
$97,000 and a deferred tax liability of $5.1 million at December 31,
1996 which would have been recorded if the Company's predecessor had
been required to pay federal income taxes.
(5) EBITDA represents net income plus income taxes, interest expense and
depreciation, depletion and amortization expense. EBITDA should not be
considered in isolation or as a substitute for net income, cash flows
from operating activities or any other measure of financial performance
prepared in accordance with generally accepted accounting principles or
as a measure of a company's profitability or liquidity.
(6) Cash flow from operations represents net income plus non-cash items.
Cash flow from operations should not be considered in isolation or as a
substitute for net income, cash flows from operating activities or any
other measure of financial performance prepared in accordance with
generally accepted accounting principles or as a measure of a company's
profitability or liquidity.
(7) As adjusted for the Offering and the application of the estimated $21.6
million in net proceeds. See "Use of Proceeds."
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SUMMARY RESERVE AND OPERATING DATA
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------
1992(1) 1993 1994 1995 1996(2)
------- ------ ------- ------- -------
<S> <C> <C> <C> <C> <C>
3-D SEISMIC ACQUIRED ANNUALLY:
Gross square miles........................ 288 908 423 311 655
Average project working interest.......... 17% 30% 27% 29% 37%
WELLS DRILLED ANNUALLY:
Gross wells drilled....................... 19 52 73 78 68
Net wells drilled......................... 1.5 9.2 16.8 18.5 16.0
Average drilling working interest......... 8% 18% 23% 24% 24%
ESTIMATED PROVED RESERVES (AT YEAR END)(3):
Natural gas (MMcf)........................ 57 227 3,579 4,257 10,257
Oil (MBbls)............................... 93 336 1,022 1,672 1,940
Natural gas equivalent (MMcfe)............ 614 2,243 9,710 14,288 21,895
Proved developed reserves as a percentage
of proved reserves..................... 100% 100% 76% 80% 67%
Present Value of Future Net Revenues...... $1,083 $3,158 $10,240 $18,222 $44,506
PRODUCTION VOLUMES:
Natural gas (MMcf)........................ 6 59 165 272 698
Oil (MBbls)............................... 11 50 140 177 227
Natural gas equivalent (MMcfe)............ 74 359 1,002 1,332 2,060
PERCENTAGE OF RESERVES REPLACED(4).......... 936% 533% 809% 368% 500%
PER MCFE DATA:
Natural gas and oil sales................. $ 3.32 $ 2.61 $ 2.56 $ 2.69 $ 2.98
Workstation revenue....................... 3.43 1.30 .81 .48 .30
Lease operating expenses.................. (.43) (.31) (.49) (.57) (.35)
Production taxes.......................... (.16) (.13) (.13) (.12) (.18)
General and administrative expenses....... (6.28) (3.99) (1.78) (1.42) (1.07)
------ ------ ------- ------- -------
Operating margin....................... $ (.12) $ (.52) $ .97 $ 1.06 $ 1.68
====== ====== ======= ======= =======
</TABLE>
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(1) Represents the period from inception (May 1, 1992) of the Partnership, the
Company's predecessor, through December 31, 1992. Operations of the
predecessor to the Partnership for the period from January 1, 1992 through
April 30, 1992 were insignificant. See "The Company."
(2) Net of a sale by the Company in January 1996 of its interest in certain
properties that accounted for 303 MMcf of natural gas and 277 MBbls of oil
(1,962 MMcfe of proved reserves) as of December 31, 1995.
(3) The estimates of reserve and present value data as of December 31, 1996 have
been prepared in accordance with the SEC's guidelines by Cawley, Gillespie &
Associates, Inc., the Company's independent petroleum consultants ("Cawley
Gillespie"). Cawley Gillespie's letter summarizing its December 31, 1996
reserve report is Appendix A to this Prospectus.
(4) Reserve replacement is calculated as reserve additions divided by the
Company's production for the period.
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RISK FACTORS
Any investment in the Common Stock involves a high degree of risk.
Prospective purchasers of the Common Stock should carefully consider the risk
factors set forth below, as well as the other information contained in this
Prospectus. This Prospectus contains forward-looking statements. Actual results
may differ materially from those projected in the forward-looking statements as
a result of any number of factors, including risk factors set forth below.
DEPENDENCE ON EXPLORATORY DRILLING ACTIVITIES
The Company's revenues, operating results and future rate of growth are
highly dependent upon the success of its exploratory drilling program, which
will be funded in part with the proceeds of the Offering. Exploratory drilling
involves numerous risks, including the risk that no commercially productive
natural gas or oil reservoirs will be encountered. The cost of drilling,
completing and operating wells is often uncertain, and drilling operations may
be curtailed, delayed or cancelled as a result of a variety of factors,
including unexpected drilling conditions, pressure or irregularities in
formations, equipment failures or accidents, adverse weather conditions,
compliance with governmental requirements and shortages or delays in the
availability of drilling rigs and the delivery of equipment. Despite the use of
3-D seismic and other advanced technologies, exploratory drilling remains a
speculative activity. Even when fully utilized and properly interpreted, 3-D
seismic data and other advanced technologies only assist geoscientists in
identifying subsurface structures and do not enable the interpreter to know
whether hydrocarbons are in fact present in those structures. In addition, the
use of 3-D seismic data and other advanced technologies requires greater
predrilling expenditures than traditional drilling strategies, and the Company
could incur losses as a result of such expenditures. The Company's future
drilling activities may not be successful. There can be no assurance that the
Company's overall drilling success rate or its drilling success rate for
activity within a particular province will not decline. Unsuccessful drilling
activities could have a material adverse effect on the Company's results of
operations and financial condition. The Company often gathers 3-D seismic data
over large areas. The Company's interpretation of data delineates those portions
of an area desirable for drilling. Therefore, the Company may choose not to
acquire option and lease rights prior to acquiring seismic and, in many cases,
the Company may identify a drilling location before seeking option or lease
rights in the location. Although the Company has identified numerous potential
drilling locations, there can be no assurance that they will ever be leased or
drilled or that natural gas or oil will be produced from these or any other
potential drilling locations.
VOLATILITY OF NATURAL GAS AND OIL PRICES
The Company's revenues, operating results and future rate of growth are
highly dependent upon the prices received for the Company's natural gas and oil.
Historically, the markets for natural gas and oil have been volatile and are
likely to continue to be volatile in the future. Various factors beyond the
control of the Company will affect prices of its natural gas and oil, including
worldwide and domestic supplies of natural gas and oil, the ability of the
members of the Organization of Petroleum Exporting Countries to agree to and
maintain oil price and production controls, political instability or armed
conflict in oil-producing regions, the price and level of foreign imports, the
level of consumer demand, the price and availability of alternative fuels, the
availability of pipeline capacity, weather conditions, domestic and foreign
governmental regulations and taxes, and the overall economic environment. During
1996, the high and low prices for oil on the NYMEX were $26.57 per Bbl and
$17.45 per Bbl, and the high and low prices for natural gas on the NYMEX were
$4.57 per MMBtu and $1.76 per MMBtu. It is impossible to predict future natural
gas and oil price movements with certainty. Declines in natural gas and oil
prices may materially adversely affect the Company's financial condition,
liquidity, ability to finance planned capital expenditures and results of
operations. Lower natural gas and oil prices also may reduce the amount of
natural gas and oil that the Company can produce economically. Any significant
decline in the price of oil or natural gas would adversely affect the Company's
revenues and operating income and may require a reduction in the carrying value
of the Company's natural gas and oil properties. See "Risk Factors-Uncertainty
of Reserve Information and Future Net Revenue Estimates" and "Business and
Properties -- Competition."
10
<PAGE> 11
RISKS ASSOCIATED WITH MANAGEMENT OF GROWTH AND IMPLEMENTATION OF GROWTH STRATEGY
The Company's rapid growth has placed, and is expected to continue to
place, a significant strain on the Company's financial, technical, operational
and administrative resources. As the Company increases the number of projects it
is evaluating or in which it is participating, there will be additional demands
on the Company's financial, technical and administrative resources. In addition,
the Company has only limited experience operating and managing field operations,
including drilling, and there can be no assurances that the Company will be
successful in doing so. Any increase in the Company's activities as an operator
will increase its exposure to operating hazards. See "Risk Factors -- Operating
Hazards and Uninsured Risks." The failure to continue to upgrade the Company's
technical, administrative, operating and financial control systems or the
occurrence of unexpected expansion difficulties, including difficulties in
recruiting and retaining geophysicists, geologists, engineers and sufficient
numbers of qualified personnel to enable the Company to expand its role in the
drilling and production phase, or the reduced availability of seismic gathering,
drilling or other services in the face of growing demand, could have a material
adverse effect on the Company's business, financial condition and results of
operations.
SUBSTANTIAL CAPITAL REQUIREMENTS
The Company makes and will continue to make substantial capital
expenditures in its exploration and development projects. The Company intends to
finance these capital expenditures with the net proceeds from the Offering, cash
flow from operations and its existing financing arrangements. Additional
financing may be required in the future to fund the Company's developmental and
exploratory drilling and 3-D seismic acquisition activities. No assurance can be
given as to the availability or terms of any such additional financing that may
be required or that financing will continue to be available under the existing
or new financing arrangements. If additional capital resources are not available
to the Company, its drilling and other activities may be curtailed and its
business, financial condition and results of operations could be materially
adversely affected. See "Use of Proceeds" and "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources."
HISTORICAL OPERATING LOSSES AND VARIABILITY OF OPERATING RESULTS
The Company had net losses of approximately $370,000 in 1992, $5.1 million
in 1993, $1.3 million in 1994, $1.6 million in 1995 and $450,000 in 1996. The
Company has incurred net losses in each year of operation, and there can be no
assurance that the Company will be profitable in the future. At December 31,
1996, the Company's pro forma accumulated deficit was $5.1 million, as a result
of recording deferred federal income tax expense as if the Company's partnership
predecessor was a taxable entity, and its pro forma total stockholders' equity
was $14.6 million. In addition, the Company's future operating results may
fluctuate significantly depending upon a number of factors, including industry
conditions, prices of natural gas and oil, rates of drilling success, rates of
production from completed wells and the timing of capital expenditures. This
variability could have a material adverse effect on the Company's business,
financial condition and results of operations. In addition, any failure or delay
in the realization of expected cash flows from operating activities could limit
the Company's ability to invest and participate in economically attractive
projects. See "Selected Financial Data" and "Management's Discussion and
Analysis of Financial Condition and Results of Operations."
RESERVE REPLACEMENT RISK
In general, production from natural gas and oil properties declines as
reserves are depleted, with the rate of decline depending on reservoir
characteristics. Except to the extent the Company conducts successful
exploration and development activities or acquires properties containing proved
reserves, or both, the proved reserves of the Company will decline as reserves
are produced. The Company's future natural gas and oil production is highly
dependent upon its ability to economically find, develop or acquire reserves in
commercial quantities. The business of exploring for or developing reserves is
capital intensive. To the extent cash flow from operations is reduced and
external sources of capital become limited or unavailable, the Company's ability
to make the necessary capital investment to maintain or expand its asset base of
natural gas and oil
11
<PAGE> 12
reserves would be impaired. The Company participates in a substantial percentage
of its wells as non-operator. The failure of an operator of the Company's wells
to adequately perform operations, or an operator's breach of the applicable
agreements, could adversely impact the Company. In addition, there can be no
assurance that the Company's future exploration and development activities will
result in additional proved reserves or that the Company will be able to drill
productive wells at acceptable costs. Furthermore, although the Company's
revenues could increase if prevailing prices for natural gas and oil increase
significantly, the Company's finding and development costs could also increase.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations."
OPERATING HAZARDS AND UNINSURED RISKS
The Company's operations are subject to hazards and risks inherent in
drilling for and producing and transporting natural gas and oil, such as fires,
natural disasters, explosions, encountering formations with abnormal pressures,
blowouts, cratering, pipeline ruptures and spills, any of which can result in
the loss of hydrocarbons, environmental pollution, personal injury claims and
other damage to properties of the Company and others. As protection against
operating hazards, the Company maintains insurance coverage against some, but
not all, potential losses. The Company may elect to self-insure if management
believes that the cost of insurance, although available, is excessive relative
to the risks presented. The Company generally maintains insurance for the
hazards and risks inherent in drilling for and producing and transporting
natural gas and oil and believes this insurance is adequate. Nevertheless, the
occurrence of an event that is not covered, or not fully covered, by insurance
could have a material adverse effect on the Company's financial condition and
results of operations. In addition, pollution and environmental risks generally
are not fully insurable. See "Business and Properties -- Operating Hazards and
Uninsured Risks."
UNCERTAINTY OF RESERVE INFORMATION AND FUTURE NET REVENUE ESTIMATES
Numerous uncertainties are inherent in estimating quantities of proved
reserves and their values, including many factors beyond the Company's control.
The reserve information in this Prospectus is an estimate only. Although the
Company believes these estimates are reasonable, reserve estimates are imprecise
and are expected to change as additional information becomes available.
Estimates of natural gas and oil reserves by necessity are projections
based on engineering data, and uncertainties are inherent in the interpretation
of this data, the projection of future rates of production and the timing of
development expenditures. Reserve engineering is a subjective process of
estimating underground accumulations of natural gas and oil that are difficult
to measure. The accuracy of any reserve estimate is a function of the quality of
available data, engineering and geologic interpretation, and judgment. Estimates
of economically recoverable natural gas and oil reserves and of future net cash
flows depend upon a number of variable factors and assumptions, such as
historical production from the area compared with production from other
producing areas, the assumed effects of regulations by governmental agencies,
and assumptions concerning future natural gas and oil prices, future operating
costs, severance and excise taxes, development costs and workover and remedial
costs, all of which may in fact vary considerably from actual results. For these
reasons, estimates of the economically recoverable quantities of natural gas and
oil attributable to any particular group of properties, classifications of
reserves based on risk of recovery, and estimates of the future net cash flows
may vary substantially. Moreover, there can be no assurance that the Company's
reserves will ultimately be produced or that the Company's proved undeveloped
reserves will be developed within the periods anticipated. Any significant
variance in the assumptions could materially affect the estimated quantity and
value of the Company's reserves. Actual production, revenues and expenditures
with respect to the Company's reserves will likely vary from estimates, and such
variances may be material. See "Business and Properties -- Natural Gas and Oil
Reserves."
The Present Value of Future Net Revenues referred to in this Prospectus
should not be construed as the current market value of the estimated natural gas
and oil reserves attributable to the Company's properties. In accordance with
applicable requirements of the SEC, the estimated discounted future net cash
flows from proved reserves are generally based on prices and costs as of the
date of the estimate, whereas actual future prices and costs may be materially
higher or lower. At December 31, 1996, the date Cawley Gillespie
12
<PAGE> 13
estimated the Company's reserves and present value data, the prices of natural
gas and oil on the NYMEX were $2.76 per MMBtu and $25.92 per Bbl, respectively.
At March 31, 1997, the prices were $1.93 per MMBtu and $20.41 per Bbl,
respectively. Actual future net cash flows also will be affected by factors such
as the amount and timing of actual production, supply and demand for natural gas
and oil, curtailments or increases in consumption by gas purchasers, and changes
in governmental regulations or taxation. The timing of actual future net cash
flows from proved reserves, and thus their actual present value, will be
affected by the timing of both the production and the incurrence of expenses in
connection with development and production of natural gas and oil properties. In
addition, the 10% discount factor, which must be used to calculate discounted
future net cash flows for reporting purposes, is not necessarily the most
appropriate discount factor based on interest rates in effect from time to time
and risks associated with the Company or the oil and gas industry in general.
COMPETITION
The Company operates in the highly competitive areas of natural gas and oil
exploration, exploitation, acquisition and production with other companies. In
seeking to acquire desirable producing properties or new leases for future
exploration and in marketing its natural gas and oil production, as well as in
seeking to acquire the equipment and expertise necessary to operate and develop
those properties, the Company faces intense competition from a large number of
independent, technology-driven companies as well as both major and other
independent natural gas and oil companies. Many of these competitors have
financial and other resources substantially in excess of those available to the
Company. See "Business and Properties -- Competition." The effects of this
highly competitive environment could have a material adverse effect on the
Company.
COMPLIANCE WITH GOVERNMENT REGULATIONS
The Company's business is subject to federal, state and local laws and
regulations relating to the exploration for, and the development, production and
transportation of, natural gas and oil, as well as safety matters. Although the
Company believes it is in substantial compliance with all applicable laws and
regulations, legal requirements are frequently changed and subject to
interpretation, and the Company is unable to predict the ultimate cost of
compliance with these requirements or their effect on its operations.
Significant expenditures may be required to comply with governmental laws and
regulations. See "Business and Properties -- Governmental Regulation."
COMPLIANCE WITH ENVIRONMENTAL REGULATIONS
The Company's operations are subject to complex environmental laws and
regulations adopted by federal, state and local governmental authorities.
Environmental laws and regulations are frequently changed. The implementation of
new, or the modification of existing, laws or regulations could have a material
adverse effect on the Company. The discharge of natural gas, oil, or other
pollutants into the air, soil or water may give rise to significant liabilities
on the part of the Company to the government and third parties and may require
the Company to incur substantial costs of remediation. No assurance can be given
that existing environmental laws or regulations, as currently interpreted or
reinterpreted in the future, or future laws or regulations will not materially
adversely affect the Company's results of operations and financial condition.
See "Business and Properties -- Environmental Matters."
RISK OF HEDGING ACTIVITIES
In an attempt to reduce its sensitivity to energy price volatility, the
Company uses swap arrangements that generally result in a fixed price over a
period of six months. If the Company's reserves are not produced at rates
equivalent to the hedged position, the Company would be required to satisfy its
obligations under hedging contracts on potentially unfavorable terms without the
ability to hedge that risk through sales of comparable quantities of its own
production. Further, the terms under which the Company enters into hedging
contracts are based on assumptions and estimates of numerous factors such as
cost of production and pipeline and other transportation costs to delivery
points. Substantial variations between the assumptions and estimates
13
<PAGE> 14
used by the Company and actual results experienced could materially adversely
affect the Company's anticipated profit margins and its ability to manage the
risk associated with fluctuations in natural gas and oil prices. Additionally,
hedging contracts limit the benefits the Company will realize if actual prices
rise above the contract prices. In addition, hedging contracts are subject to
the risk that the other party may prove unable or unwilling to perform its
obligations under such contracts. Any significant nonperformance could have a
material adverse financial effect on the Company. As of December 31, 1996, the
Company had approximately 37.1% of its average monthly oil production (based on
fourth quarter production) committed to hedging contracts through May 1997.
These arrangements provide for the Company to exchange 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
when the fixed price exceeds the floating price. Settlements on these swaps are
based on the difference between the average daily closing NYMEX price for a
contract month and the fixed contract price for the same month. In 1996 the
Company did not hedge any of its natural gas production. For the year ended
December 31, 1996, the Company realized a reduction in revenues attributable to
oil hedges of $301,280. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Other Matters."
MARKETABILITY OF PRODUCTION
The marketability of the Company's production depends in part upon the
availability, proximity and capacity of natural gas gathering systems, pipelines
and processing facilities. The Company delivers natural gas through gas
gathering systems and gas pipelines that it does not own. Federal and state
regulation of natural gas and oil production and transportation, tax and energy
policies, changes in supply and demand and general economic conditions all could
adversely affect the Company's ability to produce and market its natural gas and
oil. Any dramatic change in market factors could have a material adverse effect
on the Company.
DEPENDENCE ON KEY PERSONNEL
The Company has assembled a team of geologists, geophysicists and engineers
having considerable experience applying 3-D imaging technology. The Company is
dependent upon the knowledge, skills and experience of these experts to provide
3-D imaging and assist the Company in reducing the risks associated with its
participation in natural gas and oil exploration projects. In addition, the
success of the Company's business also depends to a significant extent upon the
abilities and continued efforts of its management, particularly Ben M. Brigham,
the Company's President, Chief Executive Officer and Chairman of the Board. The
Company has an employment agreement with Ben M. Brigham, but does not have an
employment agreement with any of its other employees. The Company has key man
life insurance on Mr. Brigham in the amount of $2.0 million. The loss of
services of key management personnel or the Company's technical experts, or the
inability to attract additional qualified personnel, could have a material
adverse effect on the Company's business, financial condition, results of
operations, development efforts and ability to grow. There can be no assurance
that the Company will be successful in attracting and retaining such executives,
geophysicists, geologists and engineers. See "Management -- Directors and
Executive Officers" and "Business and Properties -- Exploration Staff."
CONTROL BY EXISTING STOCKHOLDERS
Upon completion of the Offering, directors, executive officers and
principal stockholders of the Company, and certain of their affiliates, will
beneficially own approximately 74.7% of the Company's outstanding Common Stock
(approximately 71.7% if the Underwriters exercise the over-allotment option in
full). Accordingly, these stockholders, as a group, will be able to control the
outcome of stockholder votes, including votes concerning the election of
directors, the adoption or amendment of provisions in the Company's Certificate
of Incorporation or Bylaws and the approval of mergers and other significant
corporate transactions. The existence of these levels of ownership concentrated
in a few persons make it unlikely that any other holder of Common Stock will be
able to affect the management or direction of the Company. These factors may
also have the effect of delaying or preventing a change in the management or
voting control of the Company. See "Principal Stockholders."
14
<PAGE> 15
CERTAIN ANTITAKEOVER CONSIDERATIONS
The Company's Certificate of Incorporation authorizes the Board of
Directors of the Company to issue up to 10.0 million shares of preferred stock
without stockholder approval and to set the rights, preferences and other
designations, including voting rights, of those shares as the Board of Directors
may determine. These provisions, alone or in combination with the matters
described in "Risk Factors -- Control by Existing Stockholders," may discourage
transactions involving actual or potential changes of control of the Company,
including transactions that otherwise could involve payment of a premium over
prevailing market prices to holders of Common Stock. The Company also is subject
to provisions of the Delaware General Corporation Law that may make some
business combinations more difficult. See "Description of Capital Stock --
Delaware Law Provisions."
SHARES ELIGIBLE FOR FUTURE SALE; REGISTRATION RIGHTS
Sales of a substantial number of shares of Common Stock in the public
market following the Offering could adversely affect the market price for the
Common Stock. The Company believes all of the shares of Common Stock currently
outstanding, 8,928,574 shares, will be eligible for sale under Rule 144 on
February 27, 1998, subject to compliance with the volume and other limitations
of Rule 144. Investors holding 8,421,431 shares have the right to require the
Company to register the public resale of their shares before that time. Holders
of approximately 8,928,574 shares are entitled to "piggyback" registration
rights. Approximately 8,907,574 shares are subject to "lock-up" agreements from
which they will be released 180 days after the date of this Prospectus. Options
covering 644,097 shares of Common Stock have been issued, with an exercise price
of $5.00 per share, subject to vesting. See "Shares Eligible for Future Sale"
and "Description of Capital Stock -- Registration Rights."
IMMEDIATE AND SUBSTANTIAL DILUTION
Purchasers of the Common Stock in the Offering will experience an immediate
and substantial dilution in pro forma net tangible book value per share. See
"Dilution."
NO PRIOR PUBLIC MARKET; POSSIBLE STOCK PRICE VOLATILITY
Before the Offering, there has been no public market for the Common Stock,
and an active public market for the Common Stock may not develop or be
sustained. The initial public offering price will be determined through
negotiation between the Company and the Representatives of the Underwriters
based on several factors that may not be indicative of future market prices. See
"Underwriting" for a discussion of the factors to be considered in determining
the initial public offering price. The trading price of the Common Stock and the
price at which the Company may sell securities in the future could be subject to
large fluctuations in response to changes in government regulations, quarterly
variations in operating results, litigation, general market conditions, the
prices of natural gas and oil, announcements by the Company and its competitors,
the liquidity of the Company, the Company's ability to raise additional funds
and other events.
15
<PAGE> 16
THE COMPANY
Brigham was formed in February 1997 and is the holding company for Brigham
Oil & Gas, L.P. (the "Partnership"), a Texas limited partnership. Brigham, Inc.
was formed as a Texas corporation in September 1990 to pursue natural gas and
oil exploration using 3-D seismic technology. The Partnership was formed in May
1992 by contribution of assets of Brigham, Inc., and its general partners were
General Atlantic Partners III, L.P., a Delaware limited partnership ("GAP III"),
and Brigham, Inc. Under the Exchange Agreement (the "Exchange Agreement"),
effective February 27, 1997, the following transactions occurred: (i) GAP III
and the limited partners of the Partnership transferred all their partnership
interests to the Company in exchange for an aggregate of 3,314,286 shares of
Common Stock, (ii) the stockholders of Brigham, Inc. transferred all the issued
and outstanding stock of Brigham, Inc. to the Company in exchange for an
aggregate of 3,859,821 shares of Common Stock and (iii) Resource Investors
Management Company Limited Partnership ("RIMCO") exchanged all of the 5%
Convertible Unsecured Subordinated Notes of the Partnership for 1,754,464 shares
of Common Stock. These transactions are referred to in this Prospectus as the
"Exchange." Following the Exchange, the Company owns all the general and limited
partnership interests in the Partnership and no instruments, agreements or
rights exist which may be converted, exchanged into, or otherwise become
interests in the Partnership. The stockholders of Brigham, Inc. were Ben M.
Brigham, President, Chief Executive Officer and Chairman of the Board of the
Company, and Anne L. Brigham, Executive Vice President and a Director of the
Company. The limited partners of the Partnership included the following officers
and/or directors of the Company, who received shares of Common Stock as
indicated: Jon L. Glass, Vice President -- Exploration and a Director (66,964
shares); Craig M. Fleming, Chief Financial Officer (44,643 shares); David T.
Brigham, Vice President -- Legal (44,643 shares); and Harold D. Carter, a
Director (350,893 shares). As a result of the Exchange, Brigham Exploration
Company owns, directly or indirectly, all the partnership interests in the
Partnership and conducts its active business operations through the Partnership.
References to the "Company" or to "Brigham" are to Brigham Exploration Company
and its predecessors and subsidiaries, including the Partnership and Brigham,
Inc.
Brigham's principal executive offices are located at 5949 Sherry Lane,
Suite 1616, Dallas, Texas 75225, and its telephone number is (214) 360-9182. In
July 1997, the Company intends to relocate its principal executive offices to
6300 Bridgepoint Parkway, Building 2, Suite 500, Austin, Texas 78730.
USE OF PROCEEDS
The net proceeds to the Company from the sale of the shares of Common Stock
offered by the Company are approximately $21.6 million ($24.0 million if the
Underwriters exercise their over-allotment option in full), based on an initial
public offering price of $8.00 per share and after deducting the underwriting
discounts and commissions and estimated offering expenses.
The Company intends to use the net proceeds for exploration and development
activities (including 3-D seismic and land acquisition and drilling for which
the Company had budgeted approximately $27 million in 1997), repayment of all
outstanding indebtedness under the Revolving Credit Facility ($13.25 million at
May 5, 1997), and other general corporate purposes. While the Company believes
that the net proceeds from the Offering, cash flow from operations and
borrowings under the Revolving Credit Facility should allow the Company to
finance its operations at least through 1998 based on current conditions,
additional financing may be required in the future to fund the Company's 3-D
seismic acquisition and drilling programs. The interest rate for borrowings
under the Revolving Credit Facility is either the lender's base rate or LIBOR
plus from 1.75% to 2.25% depending on the amount outstanding under the facility.
At May 5, 1997 the current rate paid by the Company was 8.5%. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources -- Revolving Credit Facility" for
a description of the Revolving Credit Facility. Pending application of the net
proceeds of the Offering as described above, they will be invested in
short-term, interest-bearing instruments. The Company will not receive any of
the proceeds from the sale of Common Stock by the Selling Stockholders, which
will occur only if the Underwriters exercise their over-allotment option.
16
<PAGE> 17
DIVIDEND POLICY
The Company has never declared or paid cash dividends on its Common Stock
and anticipates that all future earnings will be retained for use in its
business. In addition, the Revolving Credit Facility prohibits the payment of
cash dividends on Common Stock. The Board of Directors of the Company may review
the Company's dividend policy from time to time in light of, among other things,
the Company's earning and financial position. See "Management's Discussion and
Analysis of Financial Condition and Results of Operation -- Liquidity and
Capital Resources" and Note 4 of Notes to Financial Statements.
DILUTION
The Company's pro forma net tangible book value at December 31, 1996 was
$14.6 million, or approximately $1.63 per share of Common Stock. Pro forma net
tangible book value per share represents the amount of total tangible assets of
the Company reduced by the amount of the Company's total liabilities, divided by
the number of shares of Common Stock outstanding. All amounts below give effect
to the Exchange. After giving effect to the sale by the Company of shares of
Common Stock in the Offering at an initial public offering price of $8.00 per
share and the application of the estimated net proceeds as described under "Use
of Proceeds," the Company's pro forma as adjusted net tangible book value as of
December 31, 1996 would have been $36.1 million, or $3.03 per share. This
represents an immediate increase in pro forma net tangible book value of $1.40
per share to the Company's existing stockholders and an immediate dilution in
pro forma net tangible book value of $4.97 per share to new investors purchasing
shares of Common Stock in the Offering. The following tables illustrates the per
share dilution in pro forma net tangible book value to new investors:
<TABLE>
<CAPTION>
AMOUNT
COMMON --------------------------
SHARES TOTAL PER SHARE
---------- -------------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Actual net tangible book value at December 31,
1996........................................... -- $ 3,244
Outstanding Common Stock......................... 3 --
Pro forma adjustments:
Exchange of common stock for Partnership
interest.................................... 7,174,107 --
Conversion of subordinated notes............... 1,754,464 16,433
Deferred tax liability......................... -- (5,112)
---------- -------
Pro forma net tangible book value at December 31,
1996........................................... 8,928,574 14,565 $ 1.63
Net offering proceeds............................ 3,000,000 21,570
---------- -------
Pro forma as adjusted net tangible book value at
December 31, 1996.............................. 11,928,574 $36,135 $ 3.03
========== =======
Initial public offering price per share..................... $ 8.00
Pro forma net tangible book value per share
of Common Stock at December 31, 1996................... $ 1.63
Increase per share attributable to new investors.......... 1.40
----------
Pro forma as adjusted net tangible book value per share..... 3.03
------
Pro forma dilution per share to new investors............... $ 4.97
======
</TABLE>
17
<PAGE> 18
The following table sets forth the number of shares of Common Stock
purchased from the Company, the total consideration paid, and the average price
per share paid by the existing stockholders and new investors (based on the
initial public offering price before deducting underwriting discounts and
commissions and estimated offering expenses):
<TABLE>
<CAPTION>
SHARES PURCHASED TOTAL CONSIDERATION AVERAGE
--------------------------- ------------------------ PRICE
NUMBER PERCENTAGE AMOUNT PERCENTAGE PER SHARE
-------------- ---------- ----------- ---------- ---------
<S> <C> <C> <C> <C> <C>
Existing stockholders........... 8,928,574 74.9% $28,433,130 54.2% $3.18
New investors................... 3,000,000 25.1 24,000,000 45.8 8.00
---------- ----- ----------- -----
Total...................... 11,928,574 100.0% $52,433,130 100.0%
========== ===== =========== =====
</TABLE>
The Company has reserved 1,588,169 shares for future issuance under the
Company's 1997 Incentive Plan. The preceding table excludes options that have
been granted to purchase 644,097 shares with an exercise price of $5.00 per
share, all of which have been granted since December 31, 1996. See
"Management -- Employee Benefit Plans -- 1997 Incentive Plan," Note 3 of Notes
to Balance Sheet and Note 8 of Notes to Financial Statements.
18
<PAGE> 19
CAPITALIZATION
The following table sets forth the capitalization of the Company (i) as of
December 31, 1996, (ii) pro forma to give effect to the Exchange and (iii) pro
forma as adjusted for the Offering and the application of the estimated $21.6
million in net proceeds described under "Use of Proceeds." The table should be
read with "Management's Discussion and Analysis of Financial Condition and
Results of Operations," the Unaudited Pro Forma Financial Statements, and the
Financial Statements and notes thereto in this Prospectus.
<TABLE>
<CAPTION>
AS OF DECEMBER 31, 1996
---------------------------------------
PRO FORMA
ACTUAL PRO FORMA(3) AS ADJUSTED(4)
------- ------------ --------------
(IN THOUSANDS)
<S> <C> <C> <C>
Total debt(1):
Notes payable.................................. $ 8,000 $ 8,000 $ --
Subordinated notes payable..................... 16,000 -- --
------- ------- -------
24,000 8,000 --
Partners' capital and stockholders' equity:
Partners' capital.............................. 3,244 -- --
Preferred Stock, $.01 par value, 10,000,000
shares authorized; no shares outstanding
actual, pro forma and pro forma as
adjusted.................................... -- -- --
Common Stock, $.01 par value, 30,000,000 shares
authorized; no shares issued and outstanding
actual; 8,928,574 shares issued and
outstanding pro forma; and 11,928,574 shares
issued and outstanding pro forma as
adjusted(2)................................. -- 89 119
Additional paid-in capital..................... -- 21,520 43,060
Unearned stock compensation.................... -- (1,932) (1,932)
Accumulated deficit............................ -- (5,112) (5,112)
------- ------- -------
Total partners' capital and stockholders'
equity...................................... 3,244 14,565 36,135
------- ------- -------
Total capitalization............................. $27,244 $22,565 $36,135
======= ======= =======
</TABLE>
- ---------------
(1) See Note 4 of Notes to Financial Statements.
(2) Excludes 1,588,169 shares of Common Stock the Company has reserved for
future issuance under the Company's 1997 Incentive Plan, of which options
have been granted since December 31, 1996 to purchase 644,097 shares with an
exercise price equal to $5.00 per share. See "Management -- Employee Benefit
Plans 1997 Incentive Plan," Note 3 of Notes to Balance Sheet and Note 8 of
Notes to Financial Statements.
(3) Pro forma adjustments include the (i) exchange of 7,174,107 shares of Common
Stock for all of the Partnership interests, (ii) exchange of 1,754,464
shares of Common Stock for the Partnership's subordinated notes payable of
$16 million and $.4 million of deferred interest, (iii) recording of
unearned compensation of $1.9 million relative to the granting of 644,097
options to employees for the purchases of the Common Stock, and (iv) the
recording of deferred federal income tax expense of $5.1 million as if the
Partnership had been a taxable entity.
(4) Pro forma as adjusted reflects the issuance of 3,000,000 shares of common
stock at the initial public offering price of $8.00 per share for proceeds
of $21,570,000, net of underwriting discounts and estimated expenses of the
Offering.
19
<PAGE> 20
SELECTED FINANCIAL DATA
The following selected financial data should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations," the Unaudited Pro Forma Financial Statements and notes thereto, and
the Financial Statements and notes thereto included elsewhere in this
Prospectus. All financial data presented, other than pro forma data, below are
derived from audited financial statements.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------
1992(1) 1993 1994 1995 1996
------- ------- ------- ------- --------
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues:
Natural gas and oil sales............................... $ 244 $ 937 $ 2,565 $ 3,578 $ 6,141
Workstation revenue..................................... 252 467 815 635 627
------- ------- ------- ------- --------
Total revenues...................................... 496 1,404 3,380 4,213 6,768
Costs and expenses:
Lease operating......................................... 32 111 491 761 726
Production taxes........................................ 12 47 126 165 362
General and administrative.............................. 462 1,433 1,785 1,897 2,199
Depletion of natural gas and oil properties............. 127 4,371(2) 1,104 1,626 2,323
Depreciation and amortization........................... 224 406 561 533 487
------- ------- ------- ------- --------
Total costs and expenses............................ 857 6,368 4,067 4,982 6,097
------- ------- ------- ------- --------
Operating income (loss)................................... (361) (4,964) (687) (769) 671
Other income (expense):
Interest income......................................... 12 6 56 128 52
Interest expense........................................ (21) (105) (668) (936) (1,173)
------- ------- ------- ------- --------
Net loss.................................................. $ (370) $(5,063) $(1,299) $(1,577) $ (450)
======= ======= ======= ======= ========
PRO FORMA STATEMENT OF OPERATIONS DATA:
Net income(3)(4).......................................... $ 69
Net income per share(3)(4)................................ $ 0.01
Weighted average shares outstanding(3).................... 9,170
STATEMENT OF CASH FLOWS DATA:
Net cash provided by (used in) operating activities....... $ (172) $ (730) $ 626 $ 1,383 $ 3,710
Net cash used in investing activities..................... (3,931) (6,983) (5,463) (8,005) (11,796)
Net cash provided by financing activities................. 4,845 7,839 4,634 7,724 7,731
OTHER FINANCIAL DATA:
Capital expenditures...................................... $ 4,285 $ 6,632 $ 5,445 $ 7,935 $ 13,612
EBITDA(5)................................................. 2 (181) 1,034 1,518 3,533
Cash flow from operations(6).............................. (19) (286) 366 582 2,360
</TABLE>
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
------------------------------------------------------------------------------------
1996
---------------------------------------------
PRO FORMA AS
1992 1993 1994 1995 ACTUAL PRO FORMA(3)(4) ADJUSTED(3)(4)(7)
------ ------- ------- ------- ------- --------------- -----------------
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Cash and cash equivalents..... $ 777 $ 903 $ 700 $ 1,802 $ 1,447 $ 1,447 $15,017
Natural gas and oil
properties, net............. 5,541 7,803 11,970 18,538 28,005 28,005 28,005
Total assets.................. 8,056 14,003 15,781 22,916 33,614 33,614 47,184
Notes payable................. -- 3,000 7,950 16,000 24,000 8,000 --
Total equity.................. 6,632 6,570 5,271 3,694 3,244 14,565 36,135
</TABLE>
- ---------------
(1) Represents the period from inception (May 1, 1992) of the Partnership, the
Company's predecessor, through December 31, 1992. Operations of the
predecessor to the Partnership for the period from January 1, 1992 through
April 30, 1992 were insignificant. See "The Company."
(2) Includes a capitalized ceiling impairment of $3.3 million in 1993.
(3) Gives effect to the Exchange (see "The Company") and the issuance of stock
options to employees under the 1997 Incentive Plan as if they had occurred
on January 1, 1996 for Statement of Operations
20
<PAGE> 21
Data and as of December 31, 1996 for Balance Sheet Data. See the Unaudited
Pro Forma Financial Statements and Note 1 of Notes to Financial Statements.
(4) Prior to the Exchange, the Company's predecessor was classified as a
partnership for federal income tax purposes. No provision has been made for
income taxes since these taxes are the responsibility of the partners. The
pro forma data reflect an income tax benefit in 1996 of $97,000 and a
deferred tax liability of $5.1 million at December 31, 1996 which would have
been recorded if the Company's predecessor had been required to pay federal
income taxes.
(5) EBITDA represents net income plus income taxes, interest expense and
depreciation, depletion and amortization expense. EBITDA should not be
considered in isolation or as a substitute for net income, cash flows from
operating activities or any other measure of financial performance prepared
in accordance with generally accepted accounting principles or as a measure
of a company's profitability or liquidity.
(6) Cash flow from operations represents net income plus non-cash items. Cash
flow from operations should not be considered in isolation or as a
substitute for net income, cash flows from operating activities or any other
measure of financial performance prepared in accordance with generally
accepted accounting principles or as a measure of a company's profitability
or liquidity.
(7) As adjusted for the Offering and the application of the $21.6 million in net
proceeds. See "Use of Proceeds."
21
<PAGE> 22
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 domestic natural gas and oil provinces. Brigham has
acquired over 3,300 square miles of 3-D seismic, identified approximately 1,200
potential drilling locations and drilled over 300 wells. The Company believes
this performance demonstrates a systematic methodology for finding natural gas
and oil in onshore domestic natural gas and oil 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. 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. Additionally, the Company manages the negotiation and drafting of
most of its geophysical exploration agreements, resulting in reduced contract
risk and more consistent deal terms. In 1995, the Company began to manage
operations, on a limited basis, through the drilling and production phases. The
Company had discovered an aggregate of 204.7 Bcfe of proved reserves as of
December 31, 1996. However, primarily due to capital constraints the Company
retained an interest in only approximately 14% of the reserves discovered, or
28.7 Bcfe. Brigham is endeavoring to increase its working interest in its
projects, based on capital availability and perceived risk, and plans to use a
portion of the proceeds of the Offering to retain a larger portion of the value
it creates.
Expenditures made in natural gas and oil exploration vary from project to
project depending primarily on the costs related to land, seismic acquisition,
drilling costs and the working interest retained by the Company. Typically, the
Company's participants bear 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 bear leasing, drilling and
completion costs in proportion to their ownership interests.
From inception through 1993, the Company acquired 1,373 square miles of 3-D
seismic in 63 projects. The majority of the Company's 3-D seismic acquisitions
were concentrated in the Horseshoe Atoll and Eastern Shelf of the Permian Basin
and the Hardeman Basin of West Texas. The Company drilled seventy-nine 3-D
delineated wells during this period, increasing its revenues from natural gas
and oil production to $936,634 in 1993. The Company's production volumes
consisted of 85% oil on an equivalent basis. The Company's average working
interest in these wells was 14%. In 1992, the Company increased its capacity to
finance its project generation and drilling activities through a $10.0 million
private placement of equity. This financing partially funded the Company's
acquisition of 908 square miles of 3-D seismic data in 32 projects in 1993,
which contributed to the Company's reserve growth in subsequent years. The
Company also issued $3.0 million of 10% Senior Secured General Obligation Notes
(the "10% Notes") in 1993.
During 1994, the Company acquired 423 square miles of 3-D seismic in 16
projects, primarily in the Horseshoe Atoll and Eastern Shelf areas of the
Permian Basin, the Hardeman Basin and the Anadarko Basin. The Company drilled
seventy-three 3-D delineated wells, increasing its revenues from natural gas and
oil production to $2.6 million. The Company's production volumes consisted of
84% oil on an equivalent basis. The Company's average working interest in wells
drilled in 1994 was 23%. To finance its project generation and drilling
activities, the Company supplemented cash flow from operations with capital from
the issuance of $4.9 million of its 10% Notes and the placement of working
interests in projects to industry participants. The Company's acquisition of
seismic data declined in 1994 compared to previous years as the Company
allocated a greater portion of its capital expenditure budget to drilling 3-D
delineated locations.
During 1995, the Company significantly expanded its efforts in the Anadarko
Basin of Texas and Oklahoma by acquiring 195 square miles of 3-D seismic in four
projects in this basin, and initiated its exploration program in the Gulf Coast
with the Esperson Dome Project (39 square miles of 3-D seismic). The Company
also continued its efforts in the Horseshoe Atoll and Eastern Shelf areas of the
Permian Basin and the Hardeman Basin by acquiring 77 square miles of 3-D
seismic. The Company drilled seventy-eight 3-D delineated wells, increasing its
revenues from natural gas and oil production to $3.6 million. The Company's
22
<PAGE> 23
production volumes consisted of 80% oil on an equivalent basis. The Company's
average working interest in wells drilled in 1995 was 24%. To finance its
project generation and drilling activities the Company supplemented cash flow
from operations with capital from the issuance of $2.6 million of the 10% Notes,
the issuance of $16.0 million principal amount of its 5% Convertible Unsecured
Subordinated Notes (the "5% Notes") and the placement of working interests in
projects to industry participants. The Company used $10.5 million of the
proceeds from the issuance of the 5% Notes to retire the then outstanding
balance of the 10% Notes.
During 1996, the Company acquired 655 square miles of 3-D seismic data and
continued to focus the majority of its 3-D exploration efforts in the Anadarko
Basin and the Gulf Coast. The Company acquired 457 square miles (70%) of the 3-D
seismic data in eight projects in the Anadarko Basin, making this basin the most
active 3-D acquisition province for the Company in 1996. Brigham also
significantly increased its Gulf Coast activity, adding eight 3-D projects, and
continued to expand its operations through staff additions and opening a Houston
office in January 1997. While an increasing portion of the Company's capital was
dedicated to 3-D seismic and land acquisition and subsequent drilling in the
Anadarko Basin and the Gulf Coast, the Company continued to allocate a
significant amount of capital to the drilling of its potential drilling
locations in the West Texas region. The Company expects that its change in
geographic focus will result in a larger percentage of its reserves consisting
of natural gas. During 1996, the Company drilled sixty-eight 3-D delineated
wells, increasing its revenues from natural gas and oil production to $6.1
million. The Company's production volumes consisted of 66% oil on an equivalent
basis. The Company's average working interest in wells drilled in 1996 was 24%.
The Company's fourth quarter 1996 revenue from natural gas and oil production
increased to $1.9 million from $955,000 in the fourth quarter of 1995. The
Company supplemented cash flow from operations with borrowings under its
Revolving Credit Facility, the sale of producing properties and the placement of
working interests in projects to industry participants to finance its project
generation and drilling activities.
The Company uses the full-cost method of accounting for its natural gas and
oil properties. Under this method, all acquisition, exploration and development
costs, including certain internal costs that are directly attributable to the
Company's acquisition, exploration and development activities, are capitalized
in the amortizable base of the "full-cost pool" as incurred. Upon the
interpretation by the Company of the 3-D seismic data associated with unproved
properties, the geological and geophysical costs of acreage that is not
specifically identified as prospective are transferred to the amortizable base.
Geological and geophysical costs associated with prospective acreage, as well as
leasehold costs, are transferred to the amortizable base 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) 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.
Once incurred, a write-down of natural gas and oil properties is not reversed at
a later date. See Note 2 of Notes to Financial Statements.
In connection with the Exchange, 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 $1.9 million, of
which approximately one-half will be added to the amortizable base of the
full-cost pool over the vesting period of the options and the balance will be
recorded as a noncash compensation expense of approximately $344,000 in 1997,
$250,000 in 1998 and an aggregate of $305,000 in the five 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. Assuming the
Exchange had occurred on December 31, 1996, the Company would have incurred an
estimated charge of $5.1 million to record a deferred tax liability primarily
reflecting the difference between the tax bases and financial statement bases of
the Partnership's natural gas and oil properties. Accordingly, the Company
anticipates that a charge approximating this amount will be recorded in the
first quarter of 1997, when the Exchange occurred.
23
<PAGE> 24
RESULTS OF OPERATIONS
The following table sets forth certain operating data for the periods
presented.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------
1994 1995 1996
------ ------ ------
<S> <C> <C> <C>
Production:
Natural gas (MMcf)..................................... 165 272 698
Oil (MBbls)............................................ 140 177 227
Natural gas equivalent (MMcfe)......................... 1,002 1,332 2,060
Average sales prices per unit(1):
Natural gas (per Mcf).................................. $ 1.76 $ 1.62 $ 2.30
Oil (per Bbl).......................................... 16.30 17.76 19.98
Natural gas equivalent (per Mcfe)...................... 2.56 2.69 2.98
Costs and expenses per Mcfe:
Lease operating........................................ $ .49 $ .57 $ .35
General and administrative............................. 1.78 1.42 1.07
Depletion of natural gas and oil properties............ 1.10 1.22 1.13
</TABLE>
- ---------------
(1) Reflects the effects of the Company's hedging activities. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Other Matters -- Hedging Activities."
Year Ended December 31, 1996 Compared to Year Ended December 31, 1995
Natural gas and oil sales. Natural gas and oil sales increased 72% from
$3.6 million in 1995 to $6.1 million in 1996. Of this increase, $2.0 million or
76% was attributable to an increase in production, and $607,894 or 24% was
attributable to an increase in the average sales price received for natural gas
and oil. Production volumes for natural gas increased 157% from 271,707 Mcf in
1995 to 698,036 Mcf in 1996. The average price received for natural gas
increased 42% from $1.62 per Mcf in 1995 to $2.30 per Mcf in 1996. Production
volumes for oil increased 28% from 176,693 Bbls in 1995 to 226,925 Bbls in 1996.
The average price received for oil increased 13% from $17.76 per Bbl in 1995 to
$19.98 per Bbl in 1996. Natural gas and oil sales were increased by production
from 43 wells completed in 1996, which was partially offset by the sale of
certain producing properties in January 1996 and the natural decline of existing
production. Hedging activities in 1996 reduced the amount by which oil revenues
increased by $301,280, compared to an increase in oil revenues of $40,849 as a
result of hedging activities in 1995.
Workstation revenue. Workstation revenue decreased 1% from $635,401 in 1995
to $627,255 in 1996, primarily as a result of a decrease in the rate at which
3-D seismic data were acquired in 1995 and interpreted in 1996. Workstation
revenue is recognized by Brigham as industry participants in the Company's
seismic programs are charged an hourly rate for the work performed by the
Company on its 3-D seismic interpretation workstations. The Company expects an
increase in workstation revenues in 1997 due to the increase in square miles of
3-D seismic acquired in 1996. Workstation revenue is expected to decline after
1997 due to the Company's increasing its interest in the square miles of 3-D
seismic acquired beginning in 1997, reducing the net hours billed to its
participants.
Lease operating expenses. Lease operating expenses decreased 5% from
$760,784 ($.57 per Mcfe) in 1995 to $725,785 ($.35 per Mcfe) in 1996. The
decrease is primarily due to the sale of certain producing properties in January
1996 partially offset by an increase in producing wells. The decrease in the per
unit rate was a result of the sale of higher cost oil wells in January 1996 and
an increase in the percentage of production from natural gas wells.
General and administrative expenses. General and administrative expenses
increased 16% from $1.9 million ($1.42 per Mcfe) in 1995 to $2.2 million ($1.07
per Mcfe) in 1996. Approximately $110,000 of the increase in 1996 resulted from
salary increases for employees, and the rest is primarily attributable to an
increase in third-party consulting fees. The decrease in the per unit rate was a
result of the increase in natural gas and oil production from 1995 to 1996. The
Company expects general and administrative expenses to
24
<PAGE> 25
increase in 1997, primarily as a result of a nonrecurring expense related to
relocating its principal executive office to Austin, Texas and the hiring of
additional personnel as the Company's operations grow.
Depletion of natural gas and oil properties. Depletion of natural gas and
oil properties increased 43% from $1.6 million ($1.22 per Mcfe) in 1995 to $2.3
million ($1.13 per Mcfe) in 1996 as a result of higher production volumes.
Interest expense. Interest expense increased 25% from $936,266 in 1995 to
$1.2 million in 1996. This increase was due to a higher average outstanding debt
balance in 1996, which was partially offset by a lower effective interest rate.
The weighted average outstanding debt balance increased 71% from approximately
$11.5 million in 1995 to $19.7 million in 1996. The effective interest rate
decreased 25% from 7.6% in 1995 to 5.7% in 1996. The increase in the weighted
average outstanding debt balance and decrease in the effective interest rate
resulted primarily from the retirement of the 10% Notes and the issuance of
$16.0 million in principal amount of the 5% Notes in August 1995. The Company
entered into the Revolving Credit Facility in April 1996, which had an effective
interest rate of 7.9% at December 31, 1996.
Year Ended December 31, 1995 Compared to Year Ended December 31, 1994
Natural gas and oil sales. Natural gas and oil sales increased 39% from
$2.6 million in 1994 to $3.6 million in 1995. Of this increase, $843,635 or 83%
was attributable to an increase in production and $168,785 or 17% was
attributable to an increase in the average sales price received for natural gas
and oil. Production volumes for natural gas increased 65% from 164,893 Mcf in
1994 to 271,707 Mcf in 1995. The average price received for natural gas
decreased 8% from $1.76 per Mcf in 1994 to $1.62 per Mcf in 1995. Production
volumes for oil increased 27% from 139,560 Bbls in 1994 to 176,693 Bbls in 1995.
The average price received for oil increased 9% from $16.30 per Bbl in 1994 to
$17.76 per Bbl in 1995. Natural gas and oil sales were increased by the
completion of 46 wells in 1995, which was partially offset by the natural
decline of existing production.
Workstation revenue. Workstation revenue decreased 22% from $814,841 in
1994 to $635,401 in 1995, primarily as a result of a decrease in the rate at
which 3-D seismic data were acquired in 1994 and interpreted in 1995.
Lease operating expenses. Lease operating expenses increased 55% from
$491,047 ($.49 per Mcfe) in 1994 to $760,784 ($.57 per Mcfe) in 1995. The
increase was primarily due to an increase in production from new wells and an
increase in the per unit rate. The per unit rate increase was due to natural
production decline in existing wells relative to the cost of operating the
wells.
General and administrative expenses. General and administrative expenses
increased 6% from $1.8 million ($1.78 per Mcfe) in 1994 to $1.9 million ($1.42
per Mcfe) in 1995. The increase was related to salary increases for existing
employees. The decrease in the per unit rate was the result of the increase in
natural gas and oil production from 1994 to 1995.
Depletion of natural gas and oil properties. Depletion of natural gas and
oil properties increased 47% from $1.1 million ($1.10 per Mcfe) in 1994 to $1.6
million ($1.22 per Mcfe) in 1995, as a result of higher production volumes and
per unit rates.
Interest expense. Interest expense increased 40% from $667,418 in 1994 to
$936,266 in 1995. This increase was due to a higher average outstanding debt
balance partially offset by a lower effective interest rate in 1995. The
weighted average outstanding debt balance increased 95% from approximately $5.9
million in 1994 to $11.5 million in 1995. The effective interest rate decreased
24% from 10.0% in 1994 to 7.6% in 1995. The increase in the weighted average
outstanding debt balance and decrease in the effective interest rate resulted
from the retirement of the 10% Notes and the issuance of $16.0 million in
principal amount of the 5% Notes in August 1995.
25
<PAGE> 26
LIQUIDITY AND CAPITAL RESOURCES
The Company's primary sources of capital have been borrowings (primarily
the 10% Notes, the 5% Notes and the Revolving Credit Facility), equity capital
from private sources, the sale of interests in projects and funds generated by
operations. The Company's primary capital requirements are 3-D seismic and land
acquisition costs and drilling expenditures.
Revolving Credit Facility. In April 1996, the Company entered into the
Revolving Credit Facility with Bank One, Texas, NA ("Bank One"). This facility
has a three-year term and provides for a maximum borrowing base of $25.0
million, subject to certain borrowing base limitations. Principal outstanding is
due at maturity on March 31, 1999 with interest due monthly. On May 5, 1997, the
borrowing base was $13.7 million and borrowings outstanding under the Revolving
Credit Facility were $13.25 million. The Company intends to repay the balance
then outstanding under the Revolving Credit Facility with a portion of the net
proceeds from the Offering. The Revolving Credit Facility will remain in place,
although the Company intends to reduce the borrowing base in the future.
The borrowing base is determined semiannually, in March and September,
based upon the Company's proved natural gas and oil reserves. The interest rate
for borrowings under the Revolving Credit Facility is either the lender's base
rate or LIBOR plus from 1.75% to 2.25%, depending on the amounts outstanding.
The Company is subject to typical covenants and restrictions under the terms of
the Revolving Credit Facility. The Company's obligations under the Revolving
Credit Facility are secured by substantially all of the natural gas and oil
properties of the Company. See Note 4 of Notes to Financial Statements.
5% Notes. In August 1995, the Company entered into a note purchase
agreement with RIMCO under which RIMCO purchased $16.0 million in convertible
subordinated notes due September 1, 2002. These notes were unsecured and bore
interest at 5% per annum, of which 3% was currently payable and 2% was deferred
and payable at the maturity date. The balance outstanding under the 10% Notes
was retired with a portion of the proceeds from the issuance of the $16.0
million in principal amount of the 5% Notes. RIMCO converted these notes and the
deferred interest thereon into a 19.65% equity interest in the Company in
February 1997. The Company will pay RIMCO an amount equal to the interest the
Company would have paid on the 5% Notes through the earlier to occur of the
closing of the Offering or September 30, 1997. See Note 4 of Notes to Financial
Statements.
Cash Flow Analysis
Cash Flows from Operating Activities. Cash flows provided by operating
activities were $3.7 million in 1996, $1.4 million in 1995 and $626,205 in 1994.
Increase in cash flows for 1996 compared to 1995 was due primarily to an
increase in natural gas and oil revenues, net of lease operating expenses,
production taxes and general and administrative expenses. The increase in cash
flows for 1995 compared to 1994 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 changes in balance sheet items.
Cash Flows from Investing Activities. Cash flows used in investing
activities increased to $11.8 million in 1996 compared to $8.0 million in 1995
and $5.5 million in 1994. These increases are directly related to an increase in
capital expenditures. Capital expenditures were $13.6 million in 1996, $7.9
million in 1995 and $5.5 million in 1994. The Company acquired 655 square miles
of 3-D seismic data in 1996, 311 square miles in 1995 and 423 square miles in
1994. The Company's drilling efforts resulted in the successful completion of 42
wells (8.5 net) in 1996, 46 wells (9.9 net) in 1995 and 45 wells (10.3 net) in
1994, which resulted in aggregate increases in PV-10 of $30.8 million in 1996,
$8.7 million in 1995 and $8.2 million in 1994. In 1996, the Company sold
producing properties for $2.1 million.
Cash Flows from Financing Activities. Cash flows from financing activities
for 1996 were $7.7 million, primarily as a result of borrowings under the
Revolving Credit Facility. Cash flows from financing activities for 1995 were
$7.7 million, primarily a result of the issuance of the 5% Notes offset by the
net repayment of the $7.9 million outstanding balance on the 10% Notes. Cash
flows from financing activities for 1994 were $4.6 million, primarily a result
of issuances of the 10% Notes.
26
<PAGE> 27
Capital Expenditures
The Company estimates capital expenditures in 1997 will be at least $27
million. The Company expects to incur these capital expenditures primarily to
drill 91 gross (23.8 net) planned wells, acquire approximately 1,400 square
miles of 3-D seismic data and continue to add to and upgrade its 3-D seismic
interpretation hardware and software. The actual number of wells drilled and
square miles acquired may differ significantly from these estimates. See
"Business and Properties -- Primary Exploration Provinces."
Due to the Company's active 3-D seismic acquisition and drilling programs,
the Company has experienced and expects to continue to experience substantial
working capital requirements. While the Company believes that the net proceeds
from the Offering, cash flow from operations and borrowings under the Revolving
Credit Facility should allow the Company to finance its operations at least
through 1998 based on current conditions, additional financing may be required
in the future to fund the Company's 3-D seismic acquisition and drilling
programs. In the event additional financing is not available, the Company may be
required to curtail these activities.
OTHER MATTERS
Hedging Activities
In 1995 the Company, in an attempt to reduce its sensitivity to volatile
commodity prices, began using swap arrangements resulting in a fixed price over
a period of six months. The Company believes that hedging, although not free of
risk, allows the Company to achieve a more predictable cash flow and to reduce
exposure to price fluctuations. However, hedging arrangements, when utilized,
limit the benefit to the Company of increases in the prices of the hedged
commodity. Moreover, the Company's present hedging arrangements apply only to a
portion of its oil production and provide only partial price protection against
declines in oil prices. As of December 31, 1996, the Company had approximately
37.1% of its average monthly oil production (based on fourth quarter production)
committed to hedging contracts through May 1997. These arrangements provide for
the Company to exchange 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 when the fixed price exceeds the
floating price. Settlements on these swaps are based on the difference between
the average daily closing NYMEX price for a contract month and the fixed
contract price for the same month. Such hedging arrangements may expose the
Company to risk of financial loss in certain circumstances. See "Risk
Factors -- Risk of Hedging Activities." Total oil purchased and sold subject to
the swap arrangements was 118,150 Bbls in 1996 and 54,900 Bbls in 1995. The
Company accounts for all these transactions as hedging activities and,
accordingly, adjusts the price received for oil and gas production during the
period the hedged transactions occur. Adjustments to the price received for oil
under the swap arrangement resulted in an increase in oil revenues of $40,849 in
1995 and a decrease in oil revenues of $301,280 in 1996. There was no hedging in
1994. The Company expects that the amount of its hedges will vary from time to
time. Outstanding hedges at December 31, 1996 were 37,750 Bbls.
Effects of Inflation and Changes in Prices
The Company's results of operations and cash flows are affected by changing
natural gas and oil prices. If the price of natural gas and oil increases
(decreases), there could be a corresponding increase (decrease) in revenues as
well as the operating costs that the Company is required to bear for operations.
Inflation has had a minimal effect on the Company.
Environmental and other Regulatory Matters
The Company's business is subject to certain federal, state and local laws
and regulations relating to the exploration for and the development, production
and transportation 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
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<PAGE> 28
unable to predict the ultimate cost of compliance with these requirements or
their effect on its operations. Any suspensions, terminations or inability to
meet applicable bonding requirements could materially adversely affect the
Company's financial condition and operations. Although significant expenditures
may be required to comply with governmental laws and regulations applicable to
the Company, compliance has not had a material adverse effect on the earnings or
competitive position of the Company. Future regulations may add to the cost of,
or significantly limit, drilling activity. See "Risk Factors -- Compliance with
Environmental Regulations," "Business and Properties -- Governmental Regulation"
and "Business and Properties -- Environmental Matters."
BUSINESS AND PROPERTIES
Brigham is an independent exploration and production company that applies
3-D seismic imaging and other advanced technologies to systematically explore
and develop onshore domestic natural gas and oil provinces. With this focus,
Brigham has achieved rapid growth in reserves, potential drilling locations and
3-D seismic data.
Since inception in 1990, Brigham has drilled over 265 exploratory and 35
development wells on its 3-D generated prospects with an aggregate 63% success
rate. From January 1, 1994 through December 31, 1996, the Company had achieved
finding and development costs of $1.05 per Mcfe. These costs included 3-D
seismic and land costs for all of the Company's 3-D delineated locations, of
which it had only drilled a portion. For the same period, the Company achieved a
drilling cost of $.68 per Mcfe of reserves discovered and, in 1996, achieved a
drilling cost of $.37 per Mcfe of reserves discovered.
Through December 31, 1996, the Company had discovered total estimated
proved reserves of 70.1 Bcf of natural gas and 22.4 MMBbls of oil, or an
aggregate of 204.5 Bcfe, 14% of which is attributable to the Company's interest.
The Company's estimated proved reserves as of December 31, 1996 were 21.9 Bcfe
having an aggregate Present Value of Future Net Revenues of $44.5 million,
compared to estimated proved reserves as of December 31, 1993 of 2.2 Bcfe having
an aggregate Present Value of Future Net Revenues of $3.2 million.
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 natural gas and oil reserves. Brigham has acquired over
3,300 square miles (2,112,000 acres) of 3-D seismic data and, from the 2,837
square miles interpreted to date, has identified approximately 1,200 potential
drilling locations. Brigham has drilled over 300 of these locations with an
average working interest of 21%. The Company generates most of its exploratory
projects and, therefore, has the ability to retain a sizeable working interest
to the extent that it decides not to place interests with industry participants.
In the projects in which it is currently acquiring 3-D seismic data, the Company
may retain an average working interest in the drilling and leasing phases in
excess of 60%.
BUSINESS STRATEGY
Brigham was founded in 1990 with the core belief that systematic
exploration applying 3-D seismic imaging and other advanced technologies could
reduce drilling risks and finding costs. Brigham's business strategy is to
continue to increase shareholder value by focusing on this core belief.
Brigham's exploration activities are concentrated primarily in three
provinces: the Anadarko Basin, the Gulf Coast and the West Texas region. The
Company is accelerating 3-D seismic activity in the Anadarko Basin and the Gulf
Coast and will continue such activity in those geologic trends of the West Texas
region where it has achieved its best results historically. Brigham is focusing
its 3-D seismic activity in provinces where it believes 3-D technology may be
effectively applied and the Company believes offer large potential reserve
volumes per well and per field, high potential production rates and multiple
producing objectives.
The Company's growth will be driven by drilling and developing its
potential drilling locations, as well as adding new locations through its
systematic 3-D seismic exploration effort. Using the proceeds of the Offering,
Brigham plans to accelerate growth by (i) increasing the working interest it
retains in drilling locations in
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<PAGE> 29
order to capture a greater share of the reserves the Company discovers, (ii)
increasing the rate at which it acquires 3-D seismic data and identifies
potential drilling locations, (iii) seeking to identify higher potential
drilling locations, (iv) increasing the rate at which potential drilling
locations are drilled and (v) reducing the time spent marketing projects to
industry participants.
COMPETITIVE ADVANTAGES
Brigham believes that its knowledge base, personnel and technology provide
it with the following competitive advantages to capture undiscovered natural gas
and oil reserves.
Pioneering Innovations. In 1990 the Company pioneered the
assemblage of large scale onshore 3-D seismic projects and the use of
preseismic lease options for the systematic exploration of proven
natural gas and oil provinces. The Company believes it was one of the
first to form alliances and joint participation arrangements with
companies and individuals possessing extensive local geologic or
operating expertise to complement its 3-D exploration expertise.
Subsequent innovations include the Company's 3-D seismic acquisition
and processing alliances and its creative industry trade structures to
financially leverage its drilling program.
3-D Seismic Knowledge Base. The Company began acquiring 3-D
seismic in 1990 and drilled its first 3-D delineated well, which was a
discovery, in February 1991. Since inception, the Company has acquired
over 3,300 square miles of 3-D seismic data and drilled more than 300
wells in over 20 geologic trends in six basins and seven states. As a
result, the Company has gained extensive technological and economic
knowledge relating to the application of 3-D seismic to different
geologic trends. This experience and knowledge enable the Company to
refine its exploration techniques and identify exploration areas where
Brigham believes 3-D seismic can be applied to reduce risks and
enhance returns on its investments.
Technological Expertise. Led by its CEO, who is an experienced,
practicing geophysicist, the Company has built an exploration staff
that includes nine other geophysicists and six geologists. Brigham's
explorationists collectively have over 200 years of experience,
including over 65 years of experience using CAEX workstations, and
have expertise in many geologic trends. The Company makes extensive
use of advanced technologies, including 3-D seismic imaging and CAEX
and in-house analytical and processing capabilities, to define
drilling prospects. To support the efforts of its explorationists,
Brigham has invested in advanced hardware and software, including
twelve UNIX-based CAEX workstations.
Project Generation and Control. Brigham is not dependent on third
parties for its project flow, having generated approximately 90% of
its 3-D exploration projects. Therefore, the Company is able to manage
the predrilling exploration phases, from project conception and
assemblage through 3-D data acquisition, processing and interpretation
and subsequent leasing. Brigham believes that its management of the
exploration process enhances project quality and compresses the cycle
time, contributing to lower finding and development costs and an
enhanced project rate of return. Furthermore, the Company can
determine the level of working interest it retains and the extent to
which it manages drilling and post-drilling operations and continues
to expand its efforts in these areas.
Numerous Potential Drilling Locations. The Company has identified
approximately 1,200 3-D defined potential drilling locations in
historically productive geologic trends, of which over 300 have been
drilled. The Company anticipates drilling 91 of these locations (23.8
net) in 1997 at a cost of approximately $16 million. The Company also
anticipates acquiring approximately 1,400 square miles of 3-D seismic
data in 1997 at a net cost to the Company of approximately $5.6
million. The Company continually evaluates and prioritizes potential
drilling locations to determine whether to drill them, farm them out
or replace them with higher quality locations.
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<PAGE> 30
EXPLORATION AND OPERATING APPROACH
The Company has acquired 3-D seismic data in approximately 110 projects
covering over 3,300 square miles (2,112,000 acres) in 20 geologic trends in six
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, compressing project cycle
times and increasing project rates of return.
The Company typically acquires 3-D seismic data in and around existing
production where the Company can benefit from the mapping of producing analogs.
These 3-D defined analogs, combined with the Company's experience in drilling
over 300 wells, provide the Company a knowledge base to evaluate other potential
geologic trends, 3-D seismic projects within trends and delineated potential
drilling locations. The Company believes that this experience is a major factor
in the Company's success to date and that this knowledge base differentiates the
Company from its competitors. The Company's knowledge base assists in
identifying geologic trends where Brigham believes it can find and develop large
volumes of natural gas and oil at a low relative cost.
The Company has experience 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 by hiring new
explorationists, engaging consultants and entering into joint ventures with
industry participants. In addition, if the targeted geologic trend is extensive,
the Company typically acquires a digital data base 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
acquired digital data bases to create 3-D maps of producing reservoirs. The
Company believes its maps are more accurate than previous reservoir maps (which
generally were based on subsurface geological information and surface 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 on a proprietary basis
using vendors. Additionally, the Company acquires data through alliances
affording it the exclusive right to interpret and use data. Occasionally the
Company participates in non-proprietary group shoots of 3-D data. In its
proprietary acquisitions and alliances, Brigham selects the sites of projects,
primarily guided by its knowledge and experience in the core provinces it
explores; establishes and monitors the seismic parameters of each project for
which data is shot; and typically selects the equipment that will be used. Data
is generally priced on the basis of square miles shot. See "Business and
Properties -- Industry Alliances."
PRIMARY EXPLORATION PROVINCES
Brigham's exploration activities are concentrated primarily in three
provinces: the Anadarko Basin, the Gulf Coast and the West Texas region. Brigham
is accelerating 3-D seismic activity in the Anadarko Basin and the Gulf Coast
and will continue such activity in those geologic trends of the West Texas
region where it has achieved its best results historically. Brigham is focusing
its 3-D seismic exploration efforts in provinces where it believes 3-D
technology may be effectively applied and the Company believes offer large
potential reserve volumes per well and per field, high potential production
rates and multiple producing objectives.
Although the Company is acquiring 3-D seismic data within the provinces
listed below and has identified approximately 900 potential drilling locations
yet to be drilled in those provinces, there can be no assurance that any of the
seismic data will be acquired or will generate additional drilling locations or
that any potential drilling locations will be drilled at all or within the
expected time frame. The final determination with respect to the drilling of any
well, including those currently budgeted, will depend on a number of factors,
including (i) the results of exploration efforts and the review and analysis of
the seismic data, (ii) the availability of
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<PAGE> 31
sufficient capital resources by the Company and other participants for drilling
prospects, (iii) economic and industry conditions at the time of drilling,
including prevailing and anticipated prices for natural gas and oil and the
availability of drilling rigs and crews, (iv) the financial resources and
results of the Company and (v) the availability of leases on reasonable terms
and permitting for the potential drilling location. There can be no assurance
that the budgeted wells will, if drilled, encounter reservoirs of commercial
quantities of natural gas or oil.
<TABLE>
<CAPTION>
ADDITIONAL 3-D 1997
SEISMIC DATA ADDITIONAL BUDGETED ESTIMATED
3-D SEISMIC BUDGETED FOR TOTAL GROSS POTENTIAL WELLS 1997
DATA ACQUIRED/ ACQUISITION WELLS DRILLED DRILLING ------------ CAPITAL
PROVINCE INTERPRETED(1) IN 1997 THROUGH 1996 LOCATIONS(2) GROSS NET EXPENDITURES(3)
-------- -------------- -------------- ------------- ------------ ----- ---- ---------------
(SQUARE MILES) (SQUARE MILES) (IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
Anadarko Basin........ 1,043/942 493 31 325 41 12.3 $15,000
Gulf Coast............ 533/154 191 1 31 7 2.2 7,000
West Texas Region..... 1,552/1,552 68 255 508 41 8.2 4,000
Other(4).............. 215/189 60 11 30 2 1.1 1,000
----------- --- --- --- -- ---- -------
Total................. 3,343/2,837 812(5) 298 894 91 23.8 $27,000
=========== === === === == ==== =======
</TABLE>
- ---------------
(1) 3-D seismic data that had been or was being acquired/interpreted on February
15, 1997.
(2) The potential drilling locations that had been identified from the portion
of the 3-D seismic data that had been interpreted by February 15, 1997.
(3) 3-D seismic and land acquisition costs and drilling expenditures.
(4) Colorado, Kansas and Montana.
(5) The Company has budgeted approximately 1,400 square miles of 3-D seismic
data for acquisition in 1997, 582 of which had been acquired or were being
acquired on February 15, 1997.
Anadarko Basin. The Anadarko Basin is a prolific natural gas province that
the Company believes has been relatively under explored, particularly with
regard to deep, high potential objectives. The Anadarko Basin contains numerous
historically elusive stratigraphic targets, such as the Red Fork, Morrow and
Springer channel sands, and structural targets, such as the Hunton and Arbuckle
carbonates, which are well-suited to 3-D seismic imaging. In some cases, these
objectives have produced in excess of 30 Bcf of natural gas from a single well
at rates up to 30 MMcf of natural gas per day.
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 7,400 miles of 2-D seismic data. Working with
consulting regional geologists, the Company's explorationists integrate this
data with their extensive expertise and knowledge base to generate 3-D projects
in the Anadarko Basin.
Following its initial 3-D seismic acquisition in the province in 1991 (12.5
square miles), the Company acquired 51 square miles of 3-D seismic in 1993. Over
the last several years the Company has accelerated its activity in the Anadarko
Basin, acquiring 151 square miles of 3-D seismic in 1994, 195 square miles in
1995 and 457 square miles in 1996. The Company retained a 33% average working
interest in the 3-D seismic data it acquired in this province in 1996. The
Company believes its increased level of activity in the Anadarko Basin will be a
significant factor in the Company's growth. On February 15, 1997, the Company
had acquired or was acquiring 1,043 square miles (667,520 acres) of 3-D seismic
data in 24 projects in the Anadarko Basin.
An example of the Company's success in the Anadarko Basin is the Foster
well, drilled late in 1996 in Lipscomb County, Texas. Identified through the
Company's interpretation of its 34 square mile 3-D program, the Foster well was
drilled to a depth of 10,550 feet, where it encountered 54 feet of gross pay, 33
feet net. The well, in which Brigham has a 22.5% working interest, is currently
producing approximately 3.0 MMcf of gas per day. The field in which the well is
producing is estimated to have total recoverable reserves of 13.2 Bcf of natural
gas from the Foster well and two proved undeveloped locations that the Company
plans to drill in 1997. Brigham is currently completing an exploratory test well
on an analogous prospect in the same project and plans to test other analogous
prospects in 1997. The Company is currently processing a 43 square mile 3-D
project, in which it currently has retained a 37.5% project working interest,
adjacent to the Foster well.
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<PAGE> 32
In 1997, the Company plans to drill at least three exploratory wells to
test 3-D delineated Hunton structural prospects in which the Company's working
interest currently ranges from 25% to 42%. These prospects are adjacent to
prolific production from the Hunton formation in fields such as Buffalo Wallow
(approximately 350 Bcfe), Mathers Ranch (approximately 186 Bcfe) and Wheeler Pan
(approximately 130 Bcfe).
As of February 15, 1997, the Company had acquired 1,043 square miles
(667,520 acres) in 24 projects in the Anadarko Basin. As of December 31, 1996,
Brigham had completed 23 wells in 31 attempts (a 74% success rate) in this
province and had found cumulative proved reserves of 53.4 Bcf of natural gas and
1.7 MMBbls of oil, or an aggregate of 63.4 Bcfe, with 16.3% attributable to the
Company's interest. From inception to December 31, 1996, the Company incurred
drilling costs in this province of $.48 per Mcfe. In 1996, the Company completed
14 wells in 20 attempts, adding 38.8 Bcfe of proved reserves, with 6.7 Bcfe
attributable to the Company's interest, at a drilling cost of $.27 per Mcfe. As
of February 15, 1997, the Company had 325 3-D delineated potential drilling
locations in the Anadarko Basin, of which the Company intends to drill 41 gross
(12.3 net) wells in 1997.
Gulf Coast. The Gulf Coast is a high potential, multi-pay province that
lends itself to 3-D seismic exploration due to its substantial structural and
stratigraphic complexity. The Company has assembled a digital data base
including geographical, production, geophysical and geological information that
the Company evaluates on its CAEX workstations. Working with consulting regional
geologists the Company's explorationists integrate this data with their
extensive expertise and knowledge base to generate 3-D projects in the Gulf
Coast. Brigham's commitment to this province is evidenced by the Company's staff
additions, the opening of its Houston office and the addition of ten new 3-D
seismic projects in 1996 and 1997.
Brigham initiated its Gulf Coast effort in 1995 with the Esperson Dome
Project in Liberty County, Texas where the Company and its partners currently
control approximately 9,600 gross acres (7,500 net) through leases and farmouts
and have acquired 39 square miles of seismic data. Brigham is not required to
invest capital for its interest until payout, when it earns a variable back-in
working interest of 12% to 20%. Because payout has not yet occurred, no reserves
or production are attributed to this project. The Esperson Dome Field has
produced in excess of 59 MMBbl of oil and 60 Bcf of natural gas to date from a
section of sands in the Miocene, Vicksburg and Yegua/Cook Mountain series
ranging in depth from 1,200 feet to 10,000 feet. The Company has drilled six
wells in the project to date (one Yegua/Cook Mountain and five Vicksburg)
yielding three discoveries. The most significant of these discoveries was
drilled and completed in January 1997 and found over 70 feet of gross pay (65
feet net pay) in a Vicksburg sand at a depth of 5,300 feet. This well tested for
352 Bbls of oil and 400 Mcf of natural gas per day from approximately 20 feet of
perforations. Gross reserves attributed to this discovery and one development
well (plus an additional undrilled development location) are approximately 1.5
MMBbls of oil with associated natural gas. An additional three Vicksburg
prospects have been identified in the project. Brigham also plans to drill
additional wells testing potential prospects in the shallower Miocene sands and
the deeper Yegua/Cook Mountain Sands in the Esperson Dome Project.
In 1996 the Company initiated the Welder Ranch Project in the South Texas
Expanded Wilcox geologic trend where the Company currently controls 18,000 gross
acres (17,950 net). In and immediately adjacent to the project area production
has been established from prospective pay zones ranging in depth from 1,600 feet
in the Queen City sands to over 15,500 feet in the Lower Wilcox sands. The East
Seven Sisters Field located on the north end of the project area is producing
from the Lower Wilcox and has cumulative production exceeding 360 Bcf of natural
gas. Recent exploration by Sonat, Inc. on a 1,000 acre block located in the
interior of the Company's acreage block has yielded two Lower Wilcox wells.
Brigham is currently in the process of acquiring a 50 square mile 3-D survey
over the Welder Ranch Project that it expects to begin processing in the second
quarter of 1997 and in which the Company currently holds at least a 70% working
interest. In addition to the extensive exploration potential associated with
this project, Brigham also expects to delineate several development locations
adjacent to the recent Sonat activity. The Company is also participating in a
356 square mile 3-D seismic program immediately adjacent to the Welder Ranch
Project.
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<PAGE> 33
The Company is also undertaking exploratory projects in the prolific
Miocene trend in South Louisiana. The Company's Tigre Point Project is located
immediately south of the developing Freshwater Bayou Field where Unocal and
others have seven wells currently producing over 245 MMcf of natural gas per day
(an average of over 35 MMcf of natural gas per day from each well) from a lower
Miocene sand. This project also offers several shallower objectives as
attractive secondary targets.
As of February 15, 1997, the Company had acquired or was acquiring 533
square miles (341,120 acres) of 3-D seismic data in six projects in the onshore
Gulf Coast. The Company anticipates acquiring 191 square miles (122,240 acres)
of additional 3-D seismic data in 1997.
The Company anticipates that its increased project assemblage and 3-D
seismic acquisition activity in the Gulf Coast will generate accelerated
drilling in the province in 1997 and 1998. The Company is currently assembling
projects in the Expanded Wilcox, Expanded Vicksburg and Yegua trends in South
Texas, the Miocene trend in South Texas and South Louisiana, the Lower and
Middle Frio trends of the upper Gulf Coast of Texas. The Company has thirty-one
3-D delineated potential drilling locations in the Gulf Coast and intends to
drill 7 gross (2.2 net) wells in 1997.
West Texas Region. The Company's 3-D seismic drilling activity in the West
Texas region has been focused in the Horseshoe Atoll, the Midland Basin and the
Eastern Shelf of the Permian Basin and the Hardeman Basin. The Company plans to
continue drilling its locations in these areas. Recently the Company initiated
an exploration program in the Delaware Basin and increased its activity in
portions of geologic trends that the Company believes offer greater potential
for lower finding costs and higher returns, including the Ellenberger and
Devonian formations of the Delaware Basin and the Fusselman formation of the
Midland Basin.
One area in which the Company increased its activity is the Midland Basin,
where the Company has drilled five Fusselman discoveries and has acquired or
intends to acquire 3-D seismic in four additional projects, in which it expects
to retain working interests in excess of 50%. Currently the most significant of
these discoveries is the Elizabeth Rose Field, with gross proved reserves
estimated by Cawley Gillespie at December 31, 1996 at 2.1 MMBbls of oil. The
Company has drilled three wells in this Fusselman field that are producing a
total of approximately 500 Bbls of oil per day. Brigham's working interest in
the five Fusselman discoveries ranges from 18.75% to 38.5%. In addition, the
Company owns a 25% to 100% working interest in an additional fifty 3-D defined
potential drilling locations in the adjoining four projects. In 1997 the Company
also plans to acquire 26 square miles of 3-D seismic data in three additional
3-D projects adjacent to the Elizabeth Rose Field and to retain working
interests of 75% to 100% in these projects.
Among Brigham's higher potential West Texas Region projects is the Longhorn
Project, located in the Delaware Basin, in which the Company owns a 25% working
interest. From its 40 square mile 3-D program acquired in the third quarter of
1996, the Company has identified twenty-three 3-D potential drilling locations
and has leased 6,400 gross acres (1,600 net). The project is surrounded by
prolific production from the Devonian and Ellenberger formations at depths of
15,000 feet to 21,000 feet, in fields such as Evetts (approximately 600 Bcf of
natural gas to date from 16 wells) and War Wink South (approximately 295 Bcf of
natural gas to date from eight wells). The Company plans to spud its first deep
test in the second quarter of 1997.
As of February 15, 1997, the Company had acquired 1,552 square miles
(993,280 acres) of 3-D seismic in 73 projects in the West Texas region. As of
December 31, 1996, the Company had completed 164 wells in 255 attempts (a 64%
success rate) and had found cumulative proved reserves of 16.7 Bcf of natural
gas and 20.6 MMBbls of oil, or an aggregate of 139.8 Bcfe, with 13.0%
attributable to the Company's interest. From inception to December 31, 1996, the
Company incurred drilling costs in this province of $.76 per Mcfe. In 1996 the
Company completed 28 wells in 43 attempts in this province, adding 29.8 Bcfe of
proved reserves, with 5.7 Bcfe attributable to the Company's interest, at a
drilling cost of $.42 per Mcfe. The Company has 508 3-D delineated potential
drilling locations in the West Texas region and intends to drill 41 gross (8.2
net) wells in 1997.
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<PAGE> 34
NATURAL GAS AND OIL RESERVES
The Company's estimated total proved reserves of natural gas and oil as of
December 31, 1994, 1995 and 1996 and the present values attributable to these
reserves as of those dates were as follows:
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-----------------------------
1994 1995 1996(1)
------- ------- -------
<S> <C> <C> <C>
Estimated proved reserves
Natural gas (MMcf)................................... 3,579 4,257 10,257
Oil (MBbls).......................................... 1,022 1,672 1,940
Natural gas equivalent (MMcfe)....................... 9,710 14,288 21,895
Proved developed reserves as a percentage of proved
reserves............................................. 76% 80% 67%
Present Value of Future Net Revenues(2) (in
thousands)........................................... $10,240 $18,222 $44,506
</TABLE>
- ---------------
(1) Net of a sale by the Company in January 1996 of its interest in certain
properties that accounted for 299 MMcf of natural gas and 272 MBbls of oil
(1,931 MMcfe of proved reserves) as of December 31, 1995.
(2) The Present Value of Future Net Revenues attributable to the Company's
reserves was prepared using prices in effect at the end of the respective
periods presented discounted at 10% per annum on a pre-tax basis. The
estimated pro forma income taxes, discounted at 10% per annum, are
approximately $12.1 million, resulting in pro forma discounted net cash
flows of approximately $32.4 million as of December 31, 1996. The effects of
the Company's hedging activities were immaterial.
The average prices for the Company's reserves were $1.83 per Mcf of natural
gas and $16.19 per Bbl of oil as of December 31, 1994, $1.85 per Mcf of natural
gas and $18.22 per Bbl of oil as of December 31, 1995, and $3.62 per Mcf of
natural gas and $24.66 per Bbl of oil as of December 31, 1996. The reserve
estimates reflected above for 1996 were prepared by Cawley Gillespie, the
Company's petroleum consultants, and are part of a report on the Company's
natural gas and oil properties prepared by Cawley Gillespie, a summary of which
is Appendix A to this Prospectus.
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 natural gas and oil prices,
which have fluctuated widely in recent years. At December 31, 1996, the date
Cawley Gillespie estimated the Company's reserves and present value data, the
prices of natural gas and oil on the NYMEX were $2.76 per MMBtu and $25.92 per
Bbl, respectively. At March 31, 1997, the prices were $1.93 per MMBtu and $20.41
per Bbl, respectively. There are numerous uncertainties inherent in estimating
natural gas and oil reserves and their estimated values, including many factors
beyond the control of the Company. The reserve data set forth in this Prospectus
represents only estimates. Reservoir engineering is a subjective process of
estimating underground accumulations of natural gas and oil 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 natural gas and oil prices, operating costs
and other factors. The revisions may be material. Accordingly, reserve estimates
are often different from the quantities of natural gas and oil 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 "Risk
Factors -- Uncertainty of Reserve Information and Future Net Revenue Estimates."
Estimates with respect to proved reserves that may be developed and
produced in the future are often based upon volumetric calculations and upon
analogy to similar types of reserves rather than actual production history.
Estimates based on these methods are generally less reliable than those based on
actual production
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<PAGE> 35
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.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------
1994 1995 1996
------------ ------------ ------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ----
<S> <C> <C> <C> <C> <C> <C>
Exploratory Wells:
Natural gas................................. 6 1.8 5 1.2 4 .9
Oil......................................... 34 8.3 37 8.1 24 5.4
Non-productive.............................. 26 5.9 32 8.7 24 7.1
-- ---- -- ---- -- ----
Total............................... 66 16.0 74 18.0 52 13.4
== ==== == ==== == ====
Development Wells:
Natural gas................................. -- -- -- -- 9 1.3
Oil......................................... 5 .2 4 .6 6 1.2
Non-productive.............................. 2 .6 -- -- 1 .1
-- ---- -- ---- -- ----
Total............................... 7 .8 4 .6 16 2.6
== ==== == ==== == ====
</TABLE>
At December 31, 1996, the Company was in the process of drilling 2 gross
(.6 net) wells that are not reflected in the table.
The Company does not own any drilling rigs, and the majority of its
drilling activities are conducted by industry participant operators or
independent contractors under standard drilling contracts.
PRODUCTIVE WELLS AND ACREAGE
Productive Wells
The following table sets forth the Company's ownership interest as of
December 31, 1996 in productive natural gas and oil wells in the areas
indicated.
<TABLE>
<CAPTION>
NATURAL GAS OIL TOTAL
----------- ------------ ------------
PROVINCE GROSS NET GROSS NET GROSS NET
-------- ----- --- ----- ---- ----- ----
<S> <C> <C> <C> <C> <C> <C>
Anadarko Basin................................. 15 3.0 2 .2 17 3.2
Gulf Coast..................................... -- -- -- -- -- --
West Texas Region.............................. 3 1.1 75 17.3 78 18.4
Other.......................................... -- -- 1 .5 1 .5
-- --- -- ---- -- ----
Total................................ 18 4.1 78 18.0 96 22.1
== === == ==== == ====
</TABLE>
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 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
35
<PAGE> 36
following table sets forth the approximate developed and undeveloped acreage in
which the Company held a leasehold mineral or other interest at December 31,
1996:
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED TOTAL
-------------- ---------------- ----------------
PROVINCE GROSS NET GROSS NET GROSS NET
-------- ------ ----- ------- ------ ------- ------
<S> <C> <C> <C> <C> <C> <C>
Anadarko Basin.................... 5,646 1,536 45,037 13,669 50,683 15,205
Gulf Coast........................ -- -- 3,738 3,226 3,738 3,226
West Texas Region................. 5,087 1,307 38,106 11,380 43,193 12,687
Other............................. -- -- 161,420 58,513 161,420 58,513
------ ----- ------- ------ ------- ------
Total........................... 10,733 2,843 248,301 86,788 259,034 89,631
====== ===== ======= ====== ======= ======
</TABLE>
In addition, the Company has preseismic lease options to acquire an
additional 107,711 acres, substantially all of which expire within one year.
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 or production has been obtained from the acreage
subject to the lease prior to that date, in which event the lease will remain in
effect until the cessation of production. The following table sets forth the
minimum remaining terms of leases for the gross and net undeveloped acreage:
<TABLE>
<CAPTION>
ACRES EXPIRING
-----------------
GROSS NET
------- ------
<S> <C> <C>
Twelve Months Ending:
December 31, 1997......................................... 59,133 19,695
December 31, 1998......................................... 114,661 41,469
December 31, 1999......................................... 48,928 5,609
Thereafter................................................ 25,579 20,015
------- ------
Total............................................. 248,301 86,788
======= ======
</TABLE>
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
natural gas and oil for the periods indicated.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------
1994 1995 1996
------ ------ ------
<S> <C> <C> <C>
Production:
Natural gas (MMcf)...................................... 165 271 698
Oil (MBbls)............................................. 140 177 227
Natural gas equivalent (MMcfe).......................... 1,002 1,332 2,060
Average sales price:
Natural gas (per Mcf)................................... $ 1.76 $ 1.62 $ 2.30
Oil (per Bbl)........................................... 16.30 17.76 19.98
Average production expenses and taxes (per Mcfe).......... $ .62 $ .69 $ .53
</TABLE>
36
<PAGE> 37
COSTS INCURRED AND CAPITALIZED COSTS
The costs incurred in natural gas and oil acquisition, exploration and
development activities follow (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
------------------
1995 1996
------- -------
<S> <C> <C>
Costs incurred for the year:
Exploration............................................... $ 6,893 $10,527
Property acquisition...................................... 1,885 6,195
Development............................................... 713 1,328
Proceeds from participants................................ (1,296) (4,111)
------- -------
$ 8,195 $13,939
======= =======
</TABLE>
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.
EXPLORATION STAFF
Over the last six years the Company has assembled an exploration staff that
includes nine geophysicists, six geologists, one petroleum engineer, three
computer applications specialists, three geophysical/geological/engineering
technicians, four landmen and three lease and division order analysts. Brigham's
nine 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 have over 200
years of exploration experience and approximately 65 years of 3-D CAEX
workstation experience, most of which was acquired at Brigham and various major
and large independent oil companies. The Company complements and leverages its
exploration staff by seeking out alliances or retainer relationships with
geologists having extensive experience in a particular area of interest.
3-D SEISMIC TECHNOLOGY
The Company's strategy is to use 3-D seismic and other advanced
technologies, including CAEX, to systematically explore and develop domestic
onshore natural gas and oil provinces. In general, 3-D seismic is the process of
acquiring seismic data along multiple lines and grids. The primary advantage of
3-D seismic over 2-D seismic is that it provides information with respect to
multiple horizontal and vertical points within a geologic formation instead of
information on a single vertical line or multiple vertical lines within the
formation. Acquiring larger amounts of data relating to a geologic formation
allows a user to better correlate the data and, in some cases, obtain a greater
understanding and image of the formation. Although it is impossible to predict
with certainty the specific configuration or composition of any underground
geologic formation, the use of 3-D seismic data provides clearer and more
accurate projected images of complex geologic formations, which can assist a
user in evaluating whether to drill for natural gas and oil 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 natural gas and oil reserves. This process relies on a comparison
of actual data with respect to the potential drilling location and historical
data with respect to the density and sonic characteristics
37
<PAGE> 38
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 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, SeisCube, SurfCube, ZAP, Zmap+, ARIES,
SynTool, Poststack, Continuity Cube, TDQ, AutoPix, MapView, GeoViz, Voxels,
SynView, CSA (Computed Seismic Attributes), Surface Slice, Hampson -- Russell
AVO Analysis and Modeling and ZEH Graphics CGMage Builder (graphics montage
tool).
The Company believes that its use of 3-D seismic technology provides it
with a number of benefits in the exploration, delineation and development
process that are not generally available to those who only use 2-D seismic data
and conventional processing methods. In particular, the Company believes that it
obtains clearer and more accurate projected images of underground formations
through computer modeling, and is therefore better able to identify potential
locations of hydrocarbon accumulations based on the characteristics of the
formations and analogies made with nearby fields and formations where
hydrocarbons have been found. This enhanced data has been used to assist the
Company in eliminating potential drilling locations that might otherwise have
been drilled had the Company relied solely on 2-D seismic data. This data has
also been used to assist the Company in attempting to identify the most
desirable location for the wellbore to increase the prospects of a successful
exploratory or development well and production from the reservoir.
INDUSTRY ALLIANCES
Pursuant to an alliance with Veritas Seismic Ltd., Brigham has acquired
approximately 400 square miles of 3-D seismic data in the Anadarko Basin and has
agreed to acquire from 700 to 1,375 additional square miles of data to be
divided among numerous projects in that province. In exchange for the Company's
commitment to Veritas, the Company and its assignees only pay a portion of the
3-D acquisition costs as the data is acquired. As the Company leases acreage or
drills wells, it pays Veritas the balance of the costs in the form of leasing
and drilling fees. Veritas has agreed to make a designated 3-D seismic crew
available to the Company on a continuous basis and, as long as the Company has a
project area ready for surveying and field seismic acquisition, to send the crew
from one project area to the next without interruption. If the Company does not
have a project area designated upon completion of one project, and Veritas has
not been able to secure an intervening project from a third party, the Company
is obligated to pay Veritas a stand-by fee. The Company has never incurred a
stand-by fee to Veritas. These arrangements afford the Company access to 3-D
seismic data acquisition in a compressed cycle time, providing the Company with
operational efficiencies.
In addition, Veritas currently maintains and operates two seismic data
processing workstations in Brigham's offices. Supervised by Brigham's
geophysicists, the vendor's employees process in the Company's offices most of
the Company's 3-D data. The associated improvement in communication and
integration, from field data acquisition to processing, reduces project cycle
times, and therefore costs, while improving the quality of the data for
Brigham's subsequent interpretation.
The Company has entered into alliances with Vintage Petroleum, Inc.
("Vintage") and Stephens Production Company ("Stephens") providing for their
participation with Brigham in all projects that the Company conducts within the
3-D seismic program that it is now completing with Veritas in the Anadarko
Basin. Under that program, the Company and its participants have acquired 400
square miles of data and may acquire up to 275 more. Vintage and Stephens bear a
disproportionate share of all pre-seismic and certain seismic costs on all
projects in the program. Net of the interests of Vintage and Stephens, the
Company holds a 37.5% interest in the program. The Company believes that this
leveraging of its costs is possible because of the expertise and knowledge that
the Company has developed, enabling the Company to build its revenue and cash
flow base at a time when it has been capital constrained. With respect to a
subsequent program with
38
<PAGE> 39
Veritas anticipated to start in July 1997 -- in which the Company plans to
acquire from 500 to 1,100 square miles of 3-D seismic data -- the Company plans
to retain at least a 75% working interest.
In order to participate in wells drilled by the Company between April 1,
1996 and March 31, 1997, each of Gasco Limited Partnership ("Gasco") and Middle
Bay Oil Company, Inc. ("Middle Bay") agreed to fund 25% of the Company's
drilling costs and 12.5% of its completion cost for each well. In return, the
Company assigned to each an undivided 12.5% of the Company's interest in the
leasehold allocated to each completed well. As a result, the Company pays for
50% of costs attributable to its working interest to casing point, and 75% of
its completion costs, for 75% of its original working interest. The Company is
currently in discussions with Gasco to renew its agreement, although the
percentages of costs borne and interest assigned may vary under any renewal or
extension of this agreement. The Company believes that these agreements have
been beneficial because they have allowed the Company to leverage its working
interests in its properties by requiring it to bear a smaller proportion of
costs than it has retained in working interests.
NATURAL GAS AND OIL MARKETING AND MAJOR CUSTOMERS
Most of the Company's natural gas and oil production is sold by its
operators 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, 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 oil or natural gas production, market, economic
and regulatory factors may in the future materially affect the Company's ability
to sell its oil or natural gas production. See "Risk Factors -- Volatility of
Natural Gas and Oil Prices" and "Risk Factors -- Marketability of Production"
and "Management's Discussion and Analysis of Financial Condition and Results of
Operations." For the year ended December 31, 1996, sales to Cobra Oil and Gas
Corporation, Maynard Oil Company and Scurlock Permian Corporation were
approximately 16%, 12% and 10%, respectively, of the Company's natural gas and
oil revenues. Due to the availability of other markets and pipeline connections,
the Company does not believe that the loss of any single natural gas or oil
customer would have a material adverse effect on the Company's results of
operations.
COMPETITION
The oil and gas industry is highly competitive in all of its phases. The
Company encounters competition from other oil and gas companies in all areas of
its operations, including the acquisition of seismic options and lease options
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 and which, in many instances, have
been engaged in the exploration and production business for a much longer time
than the Company. Such companies may be able to pay more for seismic and lease
options on natural gas and oil 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 "Risk
Factors -- Competition" and "Risk Factors -- Substantial Capital Requirements."
OPERATING HAZARDS AND UNINSURED RISKS
Drilling activities are subject to many risks, including the risk that no
commercially productive reservoirs will be encountered. There can be no
assurance that new wells drilled by the Company will be productive or that the
Company will recover all or any portion of its investment. Drilling for natural
gas and oil may involve
39
<PAGE> 40
unprofitable efforts, not only from dry wells, but from wells that are
productive but do not produce sufficient net revenues to return a profit after
drilling, operating and other costs. The cost of drilling, completing and
operating wells is often uncertain. The Company's drilling operations may be
curtailed, delayed or canceled as a result of numerous factors, many of which
are beyond the Company's control, including title problems, weather conditions,
compliance with governmental requirements and shortages or delays in the
delivery of equipment and services. The Company's future drilling activities may
not be successful and, if unsuccessful, such failure may have a material adverse
effect on the Company's future results of operations and financial condition.
See "Risk Factors -- Dependence on Exploratory Drilling Activities."
In addition, the Company's 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 success, unsuccessful wells are likely to occur. There can be no
assurance that the Company's drilling program will be successful or that
unsuccessful drilling efforts will not have a material adverse effect on the
Company.
The Company's operations are subject to hazards and risks inherent in
drilling for and producing and transporting natural gas and oil, 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 natural gas and oil 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 financial condition and results of
operations.
EMPLOYEES
On February 15, 1997, the Company had 33 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 broker service
companies to provide field landmen to the Company. One of these companies,
Brigham Land Management, is owned by Vincent M. Brigham, who is the brother of
Ben M. Brigham, the Company's President, Chief Executive Officer and Chairman of
the Board. See "Certain Transactions."
OTHER FACILITIES
Through August 1997, the Company has leased approximately 17,000 square
feet of office space in Dallas, Texas, where its principal offices are located.
When the Company's lease expires, the Company plans to relocate its principal
executive offices to Austin, Texas, where it has leased approximately 28,000
square feet of office space at 6300 Bridgepoint Parkway, Building 2, Suite 500,
Austin, Texas 78730. The Company also leases a 4,100 square foot office at 450
Gears Road, Suite 240, Houston, Texas 77067.
TITLE TO PROPERTIES
The Company believes it has satisfactory title to all of its producing
properties in accordance with standards generally accepted in the oil and gas
industry. The Company's properties are subject to customary royalty interests,
liens incident to operating agreements, liens for current taxes and other
burdens which the Company believes do not materially interfere with the use of
or affect the value of such properties. The Company's Revolving Credit Facility
is secured by substantially all of the Company's natural gas and oil properties.
GOVERNMENTAL REGULATION
The Company's natural gas and oil exploration, production and related
operations are subject to extensive rules and regulations promulgated by federal
and state agencies. Failure to comply with such rules and
40
<PAGE> 41
regulations can result in substantial penalties. The regulatory burden on the
oil and gas industry increases the Company's cost of doing business and affects
its profitability. Although the Company believes it is in substantial compliance
with all applicable laws and regulations, because those laws and regulations are
frequently amended or reinterpreted, the Company is unable to predict the future
cost or impact of complying with such laws.
The State of Texas and many other states require permits for drilling
operations, drilling bonds and reports concerning operations and impose other
requirements relating to the exploration and production of natural gas and oil.
These states also have statutes or regulations addressing conservation matters,
including provisions for the unitization or pooling of natural gas and oil
properties, the establishment of maximum rates of production from wells and the
regulation of spacing, plugging and abandonment of such wells.
The Federal Energy Regulatory Commission ("FERC") regulates interstate
natural gas transportation rates and service conditions, which affect the
marketing of gas produced by the Company, as well as the revenues received by
the Company for sales of such production. Since the mid-1980s, FERC has issued a
series of orders, culminating in Order Nos. 636, 636-A and 636-B ("Order 636"),
that have significantly altered the marketing and transportation of gas. Order
636 mandates a fundamental restructuring of interstate pipeline sales and
transportation service, including the unbundling by interstate pipelines of the
sale, transportation, storage and other components of the city-gate sales
services such pipelines previously performed. One of FERC's purposes in issuing
the order was to increase competition within all phases of the natural gas
industry. Numerous parties have filed petitions for review of Order 636, as well
as orders in individual pipeline restructuring proceedings. In July 1996, Order
636 was generally upheld on appeal, and the portions remanded for further action
do not appear to materially affect the Company. Because Order 636 may be
modified as a result of the appeals, it is difficult to predict the ultimate
impact of the orders on the Company and its gas marketing efforts. Generally,
Order 636 has eliminated or substantially reduced the interstate pipelines'
traditional role as wholesalers of natural gas and has substantially increased
competition and volatility in natural gas markets.
The price the Company receives from the sale of natural gas liquids and oil
is affected by the cost of transporting products to markets. Effective January
1, 1995, FERC implemented regulations establishing an indexing system for
transportation rates for oil pipelines, which, generally, would index such rates
to inflation, subject to certain conditions and limitations. The Company is not
able to predict with certainty the effect, if any, of these regulations on its
operations. However, the regulations may increase transportation costs or reduce
well head prices for natural gas liquids and oil. See "Risk
Factors -- Compliance with Government Regulations."
ENVIRONMENTAL MATTERS
The Company's operations and properties are 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 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 and comparable state statutes impose
strict, joint and several liability on owners and operators of sites and on
persons who disposed of or arranged for the
41
<PAGE> 42
disposal of "hazardous substances" found at such sites. It is not uncommon for
the neighboring land owners and other third parties to file claims for personal
injury and property damage allegedly caused by the hazardous substances released
into the environment. The Resource Conservation and Recovery Act and comparable
state statutes govern the disposal of "solid waste" and "hazardous waste" and
authorize imposition of substantial fines and penalties for noncompliance.
Although CERCLA currently excludes petroleum from its definition of "hazardous
substance," state laws affecting the Company's operations impose clean-up
liability relating to petroleum and petroleum related products. In addition,
although RCRA classifies certain oil field wastes as "non-hazardous," such
exploration and production wastes could be reclassified as hazardous wastes
thereby making such wastes subject to more stringent handling and disposal
requirements.
Federal regulations require certain owners or operators of facilities that
store or otherwise handle oil, such as the Company, to prepare and implement
spill prevention, control countermeasure and response plans relating to the
possible discharge of oil into surface waters. The Oil Pollution Act of 1990
contains numerous requirements relating to the prevention of and response to oil
spills into waters of the United States. For onshore facilities that may affect
waters of the United States, the OPA requires an operator to demonstrate $10
million in financial responsibility, and for offshore facilities the financial
responsibility requirement is at least $35 million. 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 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 previous owners
of these interests have used operating and disposal practices that were standard
in the industry at the time, hydrocarbons or other wastes may have been disposed
of or released on or under the properties. In addition, some of the Company's
properties are operated by third parties over whom the Company has no control.
Notwithstanding the Company's lack of control over properties operated by
others, the failure of the operator to comply with applicable environmental
regulations may, in certain circumstances, adversely impact the Company. See
"Risk Factors -- Compliance with Environmental Regulations" and "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Other Matters."
LEGAL PROCEEDINGS
The Company is not a party to any material legal proceedings.
42
<PAGE> 43
MANAGEMENT
DIRECTORS AND EXECUTIVE OFFICERS
The following table sets forth certain information regarding the executive
officers and directors of the Company:
<TABLE>
<CAPTION>
NAME AGE POSITION
---- --- --------
<S> <C> <C>
Ben M. Brigham............................ 37 President, Chief Executive Officer and
Chairman of the Board
Anne L. Brigham........................... 35 Executive Vice President, Secretary and
Director
Jon L. Glass.............................. 41 Vice President -- Exploration and Director
Craig M. Fleming.......................... 39 Chief Financial Officer
David T. Brigham.......................... 36 Vice President -- Legal
A. Lance Langford......................... 35 Vice President -- Operations
Harold D. Carter.......................... 58 Consultant and Director
Alexis M. Cranberg........................ 41 Director
Gary J. Milavec........................... 35 Director
Stephen P. Reynolds....................... 45 Director
</TABLE>
Set forth below is a description of the backgrounds of the executive
officers and directors of the Company.
Ben M. "Bud" Brigham has served as President, Chief Executive Officer 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.
Anne L. Brigham has served as Executive Vice President, Secretary and a
Director of the Company since its inception in 1990. Before joining the Company
full-time in 1991, Ms. Brigham practiced law in the oil and gas and real estate
sections of Thompson & Knight, P.C. Ms. Brigham worked as a geologist for Hunt
Petroleum Corporation, an independent oil and gas exploration and production
company, for over two years before attending law school. Ms. Brigham holds a
B.S. in Geology from the University of Texas and a J.D. from Southern Methodist
University.
Jon L. Glass joined the Company in 1992 and has served as Vice
President -- Exploration and a Director of the Company since 1995. From 1984 to
1992, Mr. Glass served in various capacities with Santa Fe Minerals, an oil and
gas exploration company, in a variety of staff and managerial positions mainly
focused on Santa Fe Minerals' exploration activities in the midcontinent and
Gulf of Mexico (onshore and offshore). During this time Mr. Glass also assisted
in the development of exploration and acquisition opportunities for Santa Fe
Minerals in Canada and South America. Mr. Glass' early geological experience
includes three years with Mid-America Pipeline Company and two years with Texaco
USA, serving mainly as a midcontinent exploration geologist. Mr. Glass holds a
B.S. and an M.S. in Geology from Oklahoma State University and an M.B.A. from
the University of Tulsa.
Craig M. Fleming has served as the Chief Financial Officer of the Company
since 1993. From 1990 to 1993, Mr. Fleming served as Controller of Odyssey
Petroleum Co., Ltd., an independent energy company. From 1988 to 1990, Mr.
Fleming served as Controller and Treasurer for Harken Exploration Company, an
independent energy company. Mr. Fleming began his career with Arthur Anderson &
Co. in the Oil and Gas Audit Division and is a Certified Public Accountant. Mr.
Fleming holds a B.B.A. in Accounting from Texas A&M University.
43
<PAGE> 44
David T. Brigham joined the Company in 1992 and has served as Vice
President -- Legal of the Company since 1994. 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 and a J.D. from Texas Tech
University.
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.
Harold D. Carter has served as a Director of and consultant to the Company
since 1992. Mr. Carter has more than 30 years experience in the oil and gas
industry and has been an independent consultant since 1990. Prior to consulting,
Mr. Carter served as Executive Vice President of Pacific Enterprises Oil Company
(USA). Before that, Mr. Carter was associated for 20 years with Sabine
Corporation, ultimately serving as President and Chief Operating Officer from
1986 to 1989. Mr. Carter consults for Endowment Advisors, Inc. with respect to
its EEP Partnerships and Associated Energy Managers, Inc. with respect to its
Energy Income Fund, L.P. and is a director of Abraxas Petroleum Corporation. Mr.
Carter has a B.B.A. in Petroleum Land Management from the University of Texas
and has completed the Program for Management Development at the Harvard
University Business School.
Alexis M. Cranberg has served as a Director of the Company since 1992. Mr.
Cranberg is President of Aspect Management Corporation, an oil and gas
exploration and investment company. In addition, Mr. Cranberg is a Director for
Westport Oil and Gas Company, Inc. and a past Director of General Atlantic
Resources, Inc. and United Meridian Corporation. He holds a B.S. in Petroleum
Engineering from the University of Texas and an M.B.A. from Stanford University.
Gary J. Milavec has served as a Director of the Company since 1995. Mr.
Milavec is a Senior Vice President of RIMCO, a full service investment
management firm specializing in the energy industry. Prior to joining RIMCO in
1990, Mr. Milavec spent two years in the corporate finance department of
Rauscher Pierce Refsnes, Inc. and three years as a geological engineer with
Shell Western E&P, Inc. He also serves as a director of Universal Seismic
Associates, Inc. and Texoil, Inc. Mr. Milavec holds B.S. in Geology from the
University of Rochester, an M.S. in Geology from the University of Oklahoma and
an M.B.A. from the University of Houston.
Stephen P. Reynolds has served as a Director of the Company since 1996. Mr.
Reynolds is a managing member of General Atlantic Partners, LLC ("GAP LLC") and
has been with GAP LLC or its predecessor entities since April 1980. Mr. Reynolds
is also President of GAP III Investors, Inc., the general partner of General
Atlantic Partners III, L.P., and is a general partner and limited partner of
GAP-Brigham Partners, L.P. Mr. Reynolds is on the board of directors of Solo
Serve Corporation, a publicly traded off-price soft goods retail company, and
Computer Learning Centers, Inc., a publicly traded company providing technology
related training. Mr. Reynolds holds a B.A. in Economics from Amherst College
and a Masters degree in Accounting from New York University.
All directors are elected to serve until the next annual meeting of
stockholders and until their successors are elected and qualified. Executive
officers are generally elected annually by the Board of Directors to serve,
subject to the discretion of the Board of Directors, until their successors are
elected or appointed.
There is no family relationship between any of the directors or between any
director and any executive officer of the Company except that Ben M. Brigham and
Anne L. Brigham are married and David T. Brigham is the brother of Ben M.
Brigham. For information regarding certain business relationships between the
Company and certain of its directors, see "Certain Transactions."
COMMITTEES OF THE BOARD
Upon completion of the Offering, the Company will establish two standing
committees of the Board of Directors: an Audit Committee and a Compensation
Committee. Messrs. Carter, Cranberg and Milavec are
44
<PAGE> 45
expected to be members of the Audit Committee and Compensation Committee
following completion of the Offering. The Audit Committee will review the
functions of the Company's management and independent accountants pertaining to
the Company's financial statements and perform such other related duties and
functions as are deemed appropriate by the Audit Committee or the Board of
Directors. The Compensation Committee will recommend to the Board of Directors
the base salaries, bonuses and other incentive compensation for the Company's
officers. The Board of Directors has designated the Compensation Committee as
the administrator of the Company's 1997 Incentive Plan. See
"Management -- Employee Benefit Plans -- 1997 Incentive Plan."
DIRECTOR COMPENSATION
Fees and Expenses; Other Arrangements. Directors who are also employees of
the Company are not separately compensated for serving on the Board of
Directors. Directors who are not employees of the Company receive $5,000 per
year and $500 per meeting for their services as directors. In addition, the
Company reimburses Directors for the expenses incurred in connection with
attending meetings of the Board of Directors and its committees.
Pursuant to a consulting agreement with Harold D. Carter that expires May
1, 1997, the Company pays Mr. Carter $7,200 per month to spend approximately 50%
of his working time performing such consulting and advisory services regarding
the operations of the Company as the Company requests, including service on the
Management Committee of the Company's predecessor partnership.
Alexis M. Cranberg and Stephen P. Reynolds served on the management
committee of the Company's predecessor partnership pursuant to the terms of an
agreement with General Atlantic, and Gary J. Milavec served on the committee
pursuant to the terms of an agreement with RIMCO. The Company is not obligated
to nominate any of the three to serve as a Director of the Company in the
future.
Director Stock Options. The Company's stockholders have approved the 1997
Director Stock Option Plan, pursuant to which each newly elected nonemployee
director shall be granted an option to purchase 1,000 shares of Common Stock and
each nonemployee director will receive an option to purchase 500 shares of
Common Stock on December 31 of each year. The options under the plan are granted
at fair market value on the grant date and become exercisable, subject to
certain conditions, in five equal annual installments on the first five
anniversaries of the grant date. The options terminate ten years from the grant
date, unless terminated sooner. 25,000 shares of Common Stock have been
authorized and reserved for issuance pursuant to the plan.
LIMITATION OF LIABILITY AND INDEMNIFICATION MATTERS
In accordance with Section 102(b)(7) of the Delaware General Corporation
Law ("DGCL"), the Company's Certificate of Incorporation includes a provision
that, to the fullest extent permitted by law, eliminates the personal liability
of members of its Board of Directors to the Company or its stockholders for
monetary damages for breach of fiduciary duty as a director. Such provision does
not eliminate or limit the liability of a director (1) for any breach of a
director's duty of loyalty to the Company or its stockholders, (2) for acts or
omissions not in good faith or which involve intentional misconduct or a knowing
violation of a law, (3) for paying an unlawful dividend or approving an illegal
stock repurchase (as provided in Section 174 of the DGCL) or (4) for any
transaction from which the director derived an improper personal benefit.
The Company has entered into indemnity agreements with each of its
executive officers and directors that provide for indemnification in certain
instances against liability and expenses incurred in connection with proceedings
brought by or in the right of the Company or by third parties by reason of a
person serving as an officer or director of the Company.
The Company believes that these provisions and agreements will assist the
Company in attracting and retaining qualified individuals to serve as directors
and officers.
45
<PAGE> 46
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
None of the members of the Compensation Committee is or has been an
employee of the Company. Mr. Carter is and has been since 1992 a consultant to
the Company. No executive officer of the Company serves as a member of the Board
of Directors or compensation committee of any entity that has one or more
executive officers serving as a member of the Company's Board of Directors or
Compensation Committee. All of the Company's directors, or their affiliates,
have acquired capital stock of the Company. See "Certain Transactions."
EXECUTIVE COMPENSATION
The following table sets forth all compensation paid for the last fiscal
year to the Company's Chief Executive Officer and each of the Company's other
executive officers whose annual salary exceeded $100,000 for the fiscal year
ended December 31, 1996. The table does not include perquisites and other
personal benefits because the aggregate amount of such compensation does not
exceed the lesser of (i) $50,000 or (ii) 10% of individual combined salary and
bonus for the named executive officers in each year.
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
LONG-TERM
COMPENSATION
------------------------
ANNUAL COMPENSATION RESTRICTED SHARES
NAME AND -------------------------- STOCK UNDERLYING ALL OTHER
PRINCIPAL POSITION YEAR SALARY BONUS(1) AWARDS OPTIONS(2) COMPENSATION(3)
------------------ ---- -------- -------- ---------- ----------- ---------------
<S> <C> <C> <C> <C> <C> <C>
Ben M. Brigham............... 1996 $144,000 $15,000 -- -- $4,817
President, Chief Executive
Officer and Chairman of
the Board
Jon L. Glass................. 1996 109,782 3,223 -- -- --
Vice
President -- Exploration
Craig M. Fleming............. 1996 102,919 8,063 -- -- --
Chief Financial Officer
David T. Brigham............. 1996 94,874 10,505 -- -- --
Vice President -- Legal
</TABLE>
- ---------------
(1) Includes, for Jon L. Glass, Craig M. Fleming and David T. Brigham, bonuses
earned under the Company's Incentive Bonus Plan of $3,223, $4,202 and
$5,496, respectively. See "Employment Benefit Plans -- Incentive Bonus
Plan."
(2) Does not include options to purchase Common Stock granted in February 1997
at an exercise price of $5.00 in the amount of 208,333 shares for Jon L.
Glass, 69,444 shares for Craig M. Fleming and 69,444 shares for David T.
Brigham.
(3) Consists of premiums paid by the Company under life and disability insurance
plans of $1,404 and $3,413, respectively.
Employment Agreements
The Company employs Ben M. Brigham under an Employment Agreement (the
"Employment Agreement") as President and Chief Executive Officer of the Company
for a five year term that began in February 1997. The Employment Agreement
contains rollover provisions so that at all times the term of the Employment
Agreement shall be not less than three years. The agreement provides for an
annual salary of $275,000, which the Board of Directors may further increase
from time to time. Mr. Brigham is also entitled to an annual cash bonus, not to
exceed 75% of his then current salary, determined based on criteria established
by the Board of Directors. Under the Employment Agreement, Mr. Brigham is
entitled to participate in any employee benefit programs that the Company
provides to its executive officers. The only employee benefit programs that the
Company offers to its officers and employees are group insurance coverage and
participation
46
<PAGE> 47
in the Company's 401(k) Retirement Plan, the 1997 Incentive Plan and the
Incentive Bonus Plan. If Mr. Brigham terminates his employment for good reason,
which includes a material reduction of Mr. Brigham's position without cause or
his written consent, breach of a material provision of the Employment Agreement
or improper notice of termination, or if the Company terminates Mr. Brigham
without cause, the Company must pay Mr. Brigham a sum equal to the amount of his
annual base salary that he would have received during the remainder of his
employment term plus the average of his annual bonuses received in the preceding
two years times the number of years in the remainder of his employment term. Mr.
Brigham's agreement also contains a three-year non-compete and confidentiality
clause with standard terms.
Each of the other executive officers of the Company is a party to a
confidentiality and noncompete agreement contained in agreements relating to the
officers' restricted stock. See "Management -- Employee Benefit
Plans -- Employees' Restricted Stock."
EMPLOYEE BENEFIT PLANS
Employees' Restricted Stock. In February 1997, the Company, in connection
with the Exchange, issued 66,964 shares, 44,643 shares and 44,643 shares of
restricted stock to Jon L. Glass, Craig M. Fleming and David T. Brigham,
respectively, in exchange for restricted limited partnership interests issued to
them in 1994. Each agreement relating to the restricted stock contains
confidentiality, noncompete and vesting provisions. The shares awarded Messrs.
Brigham and Fleming vest over a three-year period -- 30% in each of July 1997
and 1998 and 40% in July 1999. 16.67% of Mr. Glass's shares have already vested,
28.33% vest in each of July 1997 and 1998, and 26.67% vest in July 1999.
1997 Incentive Plan. The Board of Directors and the stockholders of the
Company approved the adoption of the Company's 1997 Incentive Plan (the "1997
Incentive Plan") as of February 27, 1997. The Compensation Committee selects
participants in the 1997 Incentive Plan are selected by the Compensation
Committee from among those key employees and others who hold positions of
responsibility with the Company and whose performance may have a significant
effect on the success of the Company. An aggregate of 1,588,169 shares of Common
Stock have been authorized and reserved for issuance pursuant to the 1997
Incentive Plan. In March 1997, options were granted to purchase a total of
644,097 shares of Common Stock at an exercise price per share of $5.00. These
options vest over six years. Jon L. Glass, Craig M. Fleming and David T. Brigham
were granted options to purchase 208,334 shares, 69,445 shares and 69,445 shares
of Common Stock, respectively. Their options vest as follows: 30% on July 1,
1998; 20% on July 1, 1999; 16.66% on July 1, 2000; 16.67% on July 1, 2001; and
the balance on July 1, 2002.
Subject to the provisions of the 1997 Incentive Plan, the Compensation
Committee is authorized to determine the type or types of awards made to each
participant and the terms, conditions and limitations applicable to each award.
In addition, the Compensation Committee has the exclusive power to interpret the
1997 Incentive Plan and to adopt rules and regulations that it may deem
necessary or appropriate, in keeping with the objectives of the 1997 Incentive
Plan.
Pursuant to the 1997 Incentive Plan, participants will be eligible to
receive awards consisting of stock options, stock appreciation rights, stock,
restricted stock, cash or any combination of the foregoing. Stock options may be
either incentive stock options within the meaning of Section 422 of the Internal
Revenue Code of 1986, as amended, or nonqualified stock options.
Incentive Bonus Plan. In connection with the Exchange, the Company has
adopted the Incentive Bonus Plan (the "Incentive Bonus Plan") previously
established by the Company's predecessor partnership. The Incentive Bonus Plan
is designed to pay cash compensation and bonuses to eligible employees of the
Company. Under the Incentive Bonus Plan, the Company maintains an incentive
account for each calendar year (each an "Incentive Account") and a discretionary
bonus account (the "Discretionary Bonus Account"). Prior to the beginning of
each calendar year the President of the Company designates the employees of the
Company who are eligible to participate in the Incentive Account being
established for such year, and each such employee's percentage of interest (an
"Account Percentage") in such Incentive Account. Subject to certain adjustments
provided under the Incentive Bonus Plan, each Incentive Account is credited with
an
47
<PAGE> 48
amount equal to one-half of the net revenue received by the Company which is
equivalent to a one percent interest in the Company's net revenue interest in
the oil and gas produced from each Company well drilled or reentered after April
30, 1992, and the Discretionary Bonus Account is credited with an amount equal
to the amount credited to each Incentive Account. The President has discretion
to allocate a greater interest to the accounts. Within thirty days after each
March 31 and September 30, an employee who has been designated to have an
Account Percentage in the Incentive Account established for a particular year
receives cash compensation equal to his or her Account Percentage in such
Incentive Account multiplied by the amount credited to that Incentive Account
for the six-month period then ended. In addition, the President of the Company
has the discretion to award cash bonuses to any Company employee from the
amounts credited to the Discretionary Bonus Account. The participation of an
employee under the Incentive Bonus Plan terminates when he or she ceases to be
an employee of the Company for any reason. The President of the Company may
amend or terminate the Incentive Bonus Plan at any time.
CERTAIN TRANSACTIONS
In connection with the land work necessary prior to and during 3-D seismic
acquisitions, the Company engages Brigham Land Management ("BLM"), an
independent company owned and managed by Vincent M. Brigham, a brother of Ben M.
Brigham, who is the Company's President, Chief Executive Officer and Chairman of
the Board. BLM specializes in conducting the field land work necessary prior to
and during 3-D seismic acquisitions. BLM's regional expertise is in the Anadarko
Basin and the Texas Panhandle, and to a lesser extent, West Texas. BLM performs
these services for the Company using BLM's employees and independent
contractors. BLM performs approximately one-third of the Company's work in the
Anadarko Basin. In 1994, 1995 and 1996, the Company paid BLM $310,000, $382,000
and $596,000, respectively. Other participants in the Company's 3-D seismic
projects reimbursed the Company for most of these amounts. Based on its
experience with other firms in the area, the Company believes that BLM's charges
are at or below those of other firms.
In 1994, the Company, through its subsidiary Quest Resources, L.L.C.,
formed Venture Acquisitions, L.P. ("Venture") with affiliates of RIMCO, a holder
of in excess of 5% of the Common Stock, to provide the Company with the capital
to acquire interests in potential drilling locations, producing properties and
3-D seismic projects. The RIMCO affiliates have contributed $5.2 million to
Venture, and the Company has contributed $286,138. Until the first payout under
the Venture limited partnership agreement, the Company's share of all capital
costs is 5%, and the Company's share of revenues and related production expenses
and costs is 10%. Between the first and second payout levels, the Company's
share of capital costs and revenues and related production expenses and costs is
25% and thereafter increases to 50%. Venture acquired an interest in (i) a 3-D
project, including a 3-D delineated producing well, for approximately $525,000
in 1994, (ii) a 3-D project for approximately $75,000 in 1995 and (iii) two 3-D
delineated potential drilling locations and 3-D seismic data for approximately
$83,000 in 1996. The Company billed Venture approximately $3,200 in 1994,
$14,924 in 1995 and $16,500 in 1996 for its proportionate share of exploration
and overhead costs. Because RIMCO was not an affiliate of the Company when the
Venture partnership was formed, the Company believes that the terms of the
Venture partnership are no less favorable than could be obtained from an
unaffiliated third party. Gary J. Milavec, a director of the Company, is
employed by RIMCO.
In November 1994, the Company, certain RIMCO affiliates and other unrelated
industry participants entered into a geophysical exploration agreement creating
an area of mutual interest in its Esperson Dome Project in Liberty and Harris
Counties, Texas. The Company financed its participation in this project by
assigning its interest, and obligation to bear costs, to Vaquero Gas Company,
Inc. ("Vaquero"), a RIMCO affiliate, subject to a 5% net profits overriding
royalty interest and the right to receive up to 50% of Vaquero's interest on the
occurrence of certain payouts. The Company also retained responsibility for
managing the 3-D seismic data acquisition and interpretation of the data after
it had been acquired. During 1995 and 1996, the Company received approximately
$25,000 and $123,000, respectively, from the RIMCO affiliates, including
Vaquero, for workstation time and geoscientists' time in interpreting the 3-D
seismic data that were acquired. Because RIMCO was not an affiliate of the
Company when the project was initiated and the interest to
48
<PAGE> 49
Vaquero was transferred, it believes that the terms of the arrangement are no
less favorable than could be obtained from an unaffiliated third party.
In January 1997, the Company, RIMCO and Tigre Energy Corporation ("Tigre")
entered into an agreement under which the Company has been initially assigned an
undivided 25% interest (subject to a proportionately reduced 3% overriding
royalty interest) in a project located in Vermillion Parish, Louisiana in return
for paying certain costs of acquiring 3-D seismic and land within the project
area. The Company also has the option to acquire an additional 12.5% working
interest from RIMCO and an additional 37.5% working interest from Tigre in parts
of the project. The Company believes that the arrangements with RIMCO affiliates
relating to Tigre Point are on terms no less favorable than could be obtained
from an unaffiliated third party, because RIMCO and Tigre, an unaffiliated third
party, are participants in the project on substantially similar terms.
The Company and an affiliate of Universal Seismic Associates, Inc. ("USA"),
a public company in which RIMCO affiliates beneficially own approximately 18% of
the outstanding common stock, have entered into a geophysical exploration
agreement covering an area of mutual interest on the Gulf Coast. Under the terms
of the agreement, USA will conduct a 3-D seismic program established by the
Company and USA and process the data acquired under the program at cost, and the
Company will interpret the resulting seismic data for the benefit of the Company
and USA at no charge to USA. Subject to a party electing not to participate in
an acquired interest, the Company and USA will each own an undivided 50%
interest in all land interests acquired within the area of mutual interest.
Through December 31, 1996, the Company had not incurred any costs under those
arrangements. Based on its experience in acquiring 3-D seismic data, the Company
believes that it will acquire 3-D seismic data under this agreement on terms,
and that the arrangement is on terms, no less favorable than could be obtained
from an unaffiliated third party. The Company is currently negotiating with an
affiliate of USA for participation in another South Texas project in which USA
would conduct any 3-D seismic programs within the project area at USA's cost and
the Company would interpret the resulting seismic data for the benefit of the
Company and USA.
In 1993 and 1994 the Company issued to RIMCO 10% Notes in a principal
amount of $3.0 million and $4.9 million, respectively. In 1995 the Company
issued RIMCO additional 10% Notes in a principal amount of $2.6 million, and in
the same year, issued RIMCO 5% Notes in a principal amount of $16.0 million,
$10.5 million of which was used to repay all the outstanding 10% Notes. The 5%
Notes have been exchanged for 1,754,464 shares of Common Stock in the Exchange.
In 1994, 1995 and 1996, the Company paid RIMCO $591,826, $631,989 and $809,332,
respectively, in interest payments on the 5% Notes and the 10% Notes. In 1994,
1995 and 1996, the Company distributed to RIMCO $52,900, $102,107 and $82,097,
respectively for RIMCO's overriding royalty interest in certain natural gas and
oil properties. As part of the Exchange, the Company has agreed to pay to RIMCO
an amount equal to the interest the Company would have been currently paid on
the 5% Notes through the earlier to occur the date of the closing of the
Offering or September 30, 1997.
Pursuant to a consulting agreement with Harold D. Carter that expires May
1, 1997, the Company pays Mr. Carter $7,200 per month to spend approximately 50%
of his working time performing such consulting and advisory services regarding
the operations of the Company as the Company requests, including service on the
Management Committee of the Company's predecessor partnership. Pursuant to this
agreement, Mr. Carter received $72,000 in 1994, $72,000 in 1995 and $79,200 in
1996.
In 1995 and 1996, the Company paid $35,000 and $110,000 to Aspect and
affiliates of Alexis Cranberg, a director of the Company, to acquire interests
in a project in Grady County, Oklahoma and a project in Hardeman and Wilbarger
Counties, Texas and Jackson County, Oklahoma. Based on its experience in the
industry, the Company believes that these transactions are on terms no less
favorable than could be obtained from an unaffiliated third party. The Company
billed Aspect and other affiliates of Alexis Cranberg $201,000 in 1994, $13,000
in 1995 and $68,000 in 1996 for its proportionate share of exploration costs
related to the projects.
The Company has entered into a Registration Rights Agreement with General
Atlantic Partners III, L.P., GAP-Brigham Partners, L.P., RIMCO Partners, L.P.
II, RIMCO Partners, L.P. III and RIMCO
49
<PAGE> 50
Partners, L.P. IV, Ben M. Brigham, Anne L. Brigham, Harold D. Carter, Craig M.
Fleming, David T. Brigham and Jon L. Glass. Pursuant to the Registration Rights
Agreement, Anne and Ben Brigham, acting together, the RIMCO entities, acting
together, and the General Atlantic entities, acting together, each may
separately require the Company to register securities, on one occasion, if the
shares to be registered have an estimated aggregate offering price to the public
of at least $3.0 million. One additional registration is allowed if any
registrable securities requested to be included in a previous registration
statement were not disposed of in accordance with that previous registration.
The Registration Rights Agreement also provides "piggyback" registration rights
after the Offering for all registrations of registrable securities for the
Company or another security holder. In an underwritten offering, however, the
Company may exclude all or a portion of the securities being registered pursuant
to "piggyback" registration rights if the managing underwriter determines that
including those securities would raise a substantial doubt about whether the
proposed offering could be consummated. The Registration Rights Agreement
contains customary indemnity by the Company in favor of persons selling
securities in a registration governed by the Registration Rights Agreement, and
by those persons in favor of the Company, relating to the information included
in or omitted from the Registration Statement.
PRINCIPAL STOCKHOLDERS
The following table sets forth certain information regarding the beneficial
ownership of the Company's Common Stock as of May 1, 1997, by (i) each person
the Company knows to be the beneficial owner of 5% or more of the outstanding
shares of Common Stock, (ii) each named executive officer, (iii) each director
of the Company and (iv) all executive officers and directors of the Company as a
group. Except as indicated in the footnotes to this table and pursuant to
applicable community property laws, the Company believes that each stockholder
named in this table has sole investment and voting power with respect to the
shares set forth opposite such stockholder's name.
<TABLE>
<CAPTION>
SHARES BENEFICIALLY SHARES BENEFICIALLY
OWNED PRIOR TO THE OWNED AFTER THE
OFFERING(1) OFFERING(1)
------------------- -------------------
BENEFICIAL OWNER NUMBER PERCENT NUMBER PERCENT
---------------- --------- ------- --------- -------
<S> <C> <C> <C> <C>
Ben M. Brigham(2)................................ 3,848,824 43.11% 3,848,824 32.27%
5949 Sherry Lane, Suite 1616
Dallas, Texas 75225
Anne L. Brigham(2)............................... 3,848,824 43.11% 3,848,824 32.27%
5949 Sherry Lane, Suite 1616
Dallas, Texas 75225
General Atlantic Partners III, L.P.(3)........... 2,807,143 31.44% 2,807,143 23.53%
Three Pickwick Plaza, Suite 200
Greenwich, Connecticut 06830
Resource Investors Management Company Limited
Partnership(4)................................. 1,754,464 19.65% 1,754,464 14.71%
600 Travis Street, Suite 6875
Houston, Texas 77002
Craig M. Fleming(5).............................. 44,643 * 44,643 *
Jon L. Glass(6).................................. 66,964 * 66,964 *
David T. Brigham(7).............................. 45,643 * 45,643 *
Harold D. Carter................................. 341,893 3.83% 341,893 2.87%
Gary J. Milavec(8)............................... -- -- -- --
Alexis M. Cranberg............................... -- -- -- --
Stephen P. Reynolds(9)........................... -- -- -- --
All directors and executive officers as a group
(10 persons)(5)(6)(7)(8)(9)(10)................ 4,347,967 48.70% 4,347,967 36.45%
</TABLE>
50
<PAGE> 51
- ---------------
* Represents less than 1%.
(1) Shares beneficially owned and percentage of ownership are based on
8,928,574 shares of Common Stock outstanding before the Offering and
11,928,574 shares of Common Stock outstanding after the closing. Beneficial
ownership is determined in accordance with the rules of the SEC and
generally includes voting or disposition power with respect to securities.
(2) Includes 1,923,914 shares owned by Ben M. Brigham and 1,923,910 shares
owned by Anne L. Brigham, who are husband and wife; and 1,000 shares held
by David T. Brigham, as custodian for Elizabeth R. Brigham under the Texas
Uniform Transfers to Minors Act. If the Underwriters' over-allotment option
is exercised in full, (i) Anne L. Brigham and Ben M. Brigham will each sell
62,500 shares pursuant to options granted to the Underwriters and (ii) the
number and percentage of outstanding shares beneficially owned by Anne L.
Brigham and Ben M. Brigham will be 3,723,824 and 30.39%, respectively.
(3) Includes 2,679,418 shares held by General Atlantic Partners III, L.P. ("GAP
III"); and 127,725 shares held by GAP-Brigham Partners, L.P.
("GAP-Brigham"). Stephen P. Reynolds is the general partner and a limited
partner in GAP-Brigham and is President of GAP III Investors, Inc., the
general partner of GAP III.
(4) Includes 612,308 shares held by RIMCO Partners, L.P. II, 307,031 shares
held by RIMCO Partners, L.P. III and 835,125 shares held by RIMCO Partners,
L.P. IV (collectively, the "RIMCO Partnerships"). RIMCO is the general
partner of each of the RIMCO Partnerships. The general partner of RIMCO is
RIMCO Associates, Inc.
(5) Includes 44,643 shares of restricted stock, which vest as follows: 30% in
July 1997, 30% in July 1998 and 40% in July 1999.
(6) Includes 66,964 shares of restricted stock, which vest as follows: 28.33%
in July 1997, 28.33% in July 1998 and 26.67% in July 1999.
(7) Includes 44,643 shares of restricted stock, which vest as follows: 30% in
July 1997, 30% in July 1998 and 40% in July 1999.
(8) Gary J. Milavec is a Senior Vice President of RIMCO, the general partner of
each of the RIMCO Partnerships, and is a Vice President of RIMCO
Associates, Inc., the general partner of RIMCO. As such, Mr. Milavec may be
deemed to share voting and investment power with respect to the 612,308
shares held by RIMCO Partners, L.P. II, the 307,031 shares held by RIMCO
Partners, L.P. III and the 835,125 shares held by RIMCO Partners, L.P. IV.
Mr. Milavec disclaims beneficial ownership of shares beneficially owned by
RIMCO and the RIMCO Partnerships.
(9) Stephen P. Reynolds is the general partner and a limited partner in
GAP-Brigham and is President of GAP III Investors, Inc., the general
partner of GAP III. As such, Mr. Reynolds may be deemed to share voting and
investment power with respect to the 2,679,418 shares held by GAP III and
the 127,725 shares held by GAP-Brigham. Mr. Reynolds disclaims beneficial
ownership of shares owned by GAP III and GAP-Brigham except to the extent
of his pecuniary interest therein.
(10) If the Underwriters' over-allotment is exercised in full, (i) all directors
and officers as a group will sell 125,000 shares pursuant to options
granted to the Underwriters and (ii) the number and percentage of
outstanding shares beneficially owned by all directors and officers as a
group will be 4,222,967 and 34.45%, respectively.
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<PAGE> 52
DESCRIPTION OF CAPITAL STOCK
The authorized capital stock of the Company consists of 30 million shares
of Common Stock, par value $.01 per share, and 10 million shares of preferred
stock, par value $.01 per share ("Preferred Stock"). 11,928,574 shares of Common
Stock will be issued and outstanding upon completion of the Offering (12,253,574
shares if the Underwriters exercise their over-allotment option in full). As of
March 31, 1997, the Company had outstanding 8,928,574 shares of Common Stock
held of record by 11 stockholders and stock options for an aggregate of 644,097
shares.
COMMON STOCK
The holders of Common Stock are entitled to one vote for each share held of
record on all matters submitted to the stockholders. The Certificate of
Incorporation of the Company does not allow the stockholders to take action by
less than unanimous consent. Each share of Common Stock is entitled to
participate equally in dividends, if, as and when declared by the Company's
Board of Directors, and in the distribution of assets in the event of
liquidation, subject in all cases to any prior rights of outstanding shares of
Preferred Stock. The Company has never paid cash dividends on its Common Stock.
The shares of Common Stock have no preemptive or conversion rights, redemption
rights, or sinking fund provisions. The outstanding shares of Common Stock are,
and the shares of Common Stock offered hereby upon issuance and sale will be,
duly authorized, validly issued, fully paid, and nonassessable.
PREFERRED STOCK
The Company has no outstanding Preferred Stock. The Company is authorized
to issue 10 million shares of Preferred Stock. The Company's Board of Directors
may establish, without stockholder approval, one or more classes or series of
Preferred Stock having the number of shares, designations, relative voting
rights, dividend rates, liquidation and other rights, preferences, and
limitations that the Board of Directors may designate. The Company believes that
this power to issue Preferred Stock will provide flexibility in connection with
possible corporate transactions. The issuance of Preferred Stock, however, could
adversely affect the voting power of holders of Common Stock and restrict their
rights to receive payments upon liquidation of the Company. It could also have
the effect of delaying, deferring or preventing a change in control of the
Company. The Company does not currently plan to issue Preferred Stock.
DELAWARE LAW PROVISIONS
The Company is a Delaware corporation and is subject to Section 203 of the
Delaware General Corporation Law. Generally, Section 203 prohibits the Company
from engaging in a "business combination" (as defined in Section 203) with an
"interested stockholder" (defined generally as a person owning 15% or more of
the Company's outstanding voting stock) for three years following the date that
person becomes an interested stockholder, unless (a) before that person became
an interested stockholder, the Company's Board of Directors approved the
transaction in which the interested stockholder became an interested stockholder
or approved the business combination; (b) upon completion of the transaction
that resulted in the interested stockholder's becoming an interested
stockholder, the interested stockholder owns at least 85% of the voting stock
outstanding at the time the transaction commenced (excluding stock held by
directors who are also officers of the Company and by employee stock plans that
do not provide employees with the right to determine confidentially whether
shares held subject to the plan will be tendered in a tender or exchange offer);
or (c) following the transaction in which that person became an interested
stockholder, the business combination is approved by the Company's Board of
Directors and authorized at a meeting of stockholders by the affirmative vote of
the holders of at least two-thirds of the outstanding voting stock not owned by
the interested stockholder.
Under Section 203, these restrictions also do not apply to certain business
combinations proposed by an interested stockholder following the announcement or
notification of one of certain extraordinary transactions involving the Company
and a person who was not an interested stockholder during the previous three
years or who became an interested stockholder with the approval of a majority of
the Company's directors, if that
52
<PAGE> 53
extraordinary transaction is approved or not opposed by a majority of the
directors who were directors before any person became an interested stockholder
in the previous three years or who were recommended for election or elected to
succeed such directors by a majority of such directors then in office.
REGISTRATION RIGHTS
The Company has entered into a Registration Rights Agreement with 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. Pursuant to the Registration Rights Agreement, Anne and Ben Brigham,
acting together, the General Atlantic entities, acting together, and the RIMCO
entities, acting together, each may separately require the Company to register
securities, on one occasion, if the shares to be registered have an estimated
aggregate offering price to the public of at least $3 million. One additional
registration is allowed if any registrable securities requested to be included
in a previous registration statement were not disposed of in accordance with
that previous registration. The Registration Rights Agreement also provides
"piggyback" registration rights after the Offering for all registrations of
registrable securities for the Company or another security holder. In an
underwritten offering, however, the Company may exclude all or a portion of the
securities being registered pursuant to "piggyback" registration rights if the
managing underwriter determines that including those securities would raise a
substantial doubt about whether the proposed offering could be consummated. The
Registration Rights Agreement contains customary indemnity by the Company in
favor of persons selling securities in a registration governed by the
Registration Rights Agreement, and by those persons in favor of the Company,
relating to the information included in or omitted from the Registration
Statement.
TRANSFER AGENT AND REGISTRAR
The Transfer Agent and Registrar for the Common Stock is American Stock
Transfer & Trust Company.
SHARES ELIGIBLE FOR FUTURE SALE
Upon completion of the Offering, the Company will have 11,928,574 shares of
Common Stock outstanding (12,253,574 shares if the Underwriters exercise their
over-allotment option in full). Of these 11,928,574 shares, the shares of Common
Stock offered hereby will be freely transferable without restriction under the
Securities Act unless they are held by the Company's affiliates, as that term is
used in Rule 144 under the Securities Act. The Company issued the remaining
8,928,574 shares of Common Stock in reliance on exemptions from the registration
requirements of the Securities Act, and those shares are "restricted" securities
under Rule 144. Those shares may not be sold publicly unless they are registered
under the Securities Act, sold in compliance with Rule 144, or sold in a
transaction that is exempt from registration. The Company believes that the
earliest date on which the 8,928,574 shares of its Common Stock currently
outstanding will be eligible for sale under Rule 144 is February 27, 1998.
Therefore, no shares will be eligible for immediate sale in the public market
without restriction under Rule 144(k), and no shares will be eligible for
immediate sale under the volume and other limitations of Rule 144. Beginning
February 27, 1998, all of the shares of Common Stock currently outstanding will
become eligible for sale under Rule 144, based on current SEC rules and subject
to compliance with the volume and other requirements of Rule 144. Beginning
February 27, 1999, all of those shares of Common Stock will become eligible for
sale under Rule 144(k) if they are not held by affiliates of the Company.
In general, under Rule 144 a person (or persons whose sales are
aggregated), including an affiliate, who has beneficially owned shares for at
least one year is entitled to sell in broker transactions, within any three-
month period commencing 90 days after the Offering, a number of shares that does
not exceed the greater of (i) 1% of the then outstanding Common Stock
(approximately 119,000 shares immediately after the Offering) or (ii) the
average weekly trading volume in the Common Stock during the four calendar weeks
preceding the sale, subject to the filing of a Form 144 with respect to the sale
and other limitations. In addition, a person who was not an affiliate of the
Company during the three months preceding a sale and who
53
<PAGE> 54
has beneficially owned the shares proposed to be sold for at least two years is
entitled to sell the shares under Rule 144(k) without regard to the
manner-of-sale, volume and other limitations of Rule 144. The SEC has proposed
modifications to Rule 144 that could change some of these requirements.
The holders of approximately 8,421,431 shares of Common Stock and their
permitted transferees are entitled to demand registration of those shares under
the Securities Act beginning 180 days after the date of this Prospectus, and the
holders of approximately 8,928,574 shares of Common Stock are entitled to
"piggyback" registration rights. See "Description of Capital
Stock -- Registration Rights."
Approximately 8,907,574 shares of Common Stock are subject to "lock-up"
agreements; these shares will be released from such agreements 180 days after
the date of this Prospectus. See "Underwriting."
Options covering 644,097 shares of Common Stock have been issued, with an
exercise price of $5.00 per share, subject to vesting.
Prior to the Offering, there has been no public market for the securities
of the Company. No prediction can be made of the effect, if any, that the sale
or availability for sale of shares of additional Common Stock will have on the
market price of the Common Stock. Nevertheless, sales of substantial numbers of
shares by existing stockholders or by stockholders purchasing in the Offering
could have a negative effect on the market price of the Common Stock.
54
<PAGE> 55
UNDERWRITING
The Underwriters named below (the "Underwriters"), for whom Bear, Stearns &
Co. Inc., Howard, Weil, Labouisse, Friedrichs Incorporated and Rauscher Pierce
Refsnes, Inc. are acting as Representatives (the "Representatives"), have
severally agreed, subject to the terms and conditions of the Underwriting
Agreement, to purchase from the Company the aggregate number of shares of Common
Stock set forth opposite their names below:
<TABLE>
<CAPTION>
NUMBER
UNDERWRITER OF SHARES
----------- ---------
<S> <C>
Bear, Stearns & Co. Inc. ............... 852,000
Howard, Weil, Labouisse, Friedrichs
Incorporated.......................... 852,000
Rauscher Pierce Refsnes, Inc. .......... 426,000
Dillon, Read & Co. Inc. ................ 60,000
Donaldson, Lufkin & Jenrette Securities
Corporation........................... 60,000
Lazard Freres & Co. LLC................. 60,000
Oppenheimer & Co., Inc. ................ 60,000
PaineWebber Incorporated................ 60,000
Petrie Parkman & Co. ................... 60,000
Wasserstein Perella Securities, Inc. ... 60,000
Blaylock & Partners, L.P. .............. 30,000
Furman Selz LLC......................... 30,000
Gaines, Berland Inc. ................... 30,000
Hanifen, Imhoff Inc. ................... 30,000
Hoak Breedlove Wesneski & Co. .......... 30,000
Huberman Financial, Inc. ............... 30,000
Jefferies & Company, Inc. .............. 30,000
Johnson Rice & Company L.L.C. .......... 30,000
Morgan Keegan & Company, Inc. .......... 30,000
Principal Financial Securities, Inc. ... 30,000
Raymond James & Associates, Inc. ....... 30,000
San Jacinto Securities, Inc. ........... 30,000
Sanders Morris Mundy.................... 30,000
Southcoast Capital Corp. ............... 30,000
Stephens Inc. .......................... 30,000
---------
Total......................... 3,000,000
=========
</TABLE>
The Underwriting Agreement provides that the obligations of the
Underwriters thereunder are subject to the approval of certain legal matters by
their counsel and to various other conditions. The nature of the obligations of
the Underwriters is such that they are committed to purchase all of the shares
of Common Stock offered hereby if any are purchased.
The Representatives have advised the Company that the Underwriters propose
initially to offer the shares of Common Stock offered hereby directly to the
public at the initial public offering price set forth on the cover page of this
Prospectus. The Underwriters may allow a selected dealer concession of not more
than $0.34 per share, and the Underwriters may allow, and such dealers may
reallow, concessions not in excess of $0.10 per share to certain other dealers.
After the initial public offering, the public offering price and concessions and
reallowances to dealers may be changed by the Representatives.
The Company and the Selling Stockholders have granted an option to the
Underwriters, exercisable at any time during the 30-day period after the date of
this Prospectus, to purchase from the Company and the Selling Stockholders up to
an additional 450,000 shares of Common Stock at the initial public offering
price set forth on the cover page of this Prospectus, less the underwriting
discount. Of this amount, an option to purchase 325,000 shares has been granted
by the Company, 62,500 shares by Anne L. Brigham and
55
<PAGE> 56
62,500 shares by Ben M. Brigham. The Underwriters may exercise such option
solely for the purpose of covering over-allotments, if any, made in connection
with the sale of the shares of Common Stock offered hereby. To the extent that
the Underwriters exercise this option, each Underwriter will be committed,
subject to certain conditions, to purchase a number of the additional shares of
Common Stock proportionate to such Underwriter's purchase obligations set forth
in the table set forth above. In the event of a partial exercise of the option,
the option shall be satisfied first from the shares of Anne L. Brigham and Ben
M. Brigham.
During and after the Offering, the Underwriters may purchase and sell the
Common Stock in the open market. These transactions may include over-allotment
and stabilizing transactions and purchases to cover syndicate short positions
created in connection with the Offering. The Underwriters may also impose a
penalty bid, whereby selling concessions allowed to syndicate members or other
broker-dealers in respect of the Common Stock sold in the Offering for their
account may be reclaimed by the syndicate if such Common Stock is repurchased by
the syndicate in stabilizing or covering transactions. These activities may
stabilize, maintain or otherwise affect the market price of the Common Stock,
which may be higher than the price that might otherwise prevail in the open
market, and, if commenced, may be discontinued at any time.
The Underwriting Agreement provides that the Company and the Selling
Stockholders will indemnify the several Underwriters against certain
liabilities, including liabilities under the Securities Act, or will contribute
to payments the Underwriters may be required to make in respect thereof.
Each of the Company, its officers, directors, and optionholders, and the
holders of all but 21,000 shares of its outstanding Common Stock, have entered
into "lock-up" agreements with the Underwriters with respect to the sale of
shares of Common Stock. Under these agreements, the Company, its officers,
directors, certain stockholders and optionholders have agreed not to offer,
sell, agree to sell, grant any option for the sale of or otherwise dispose of,
directly or indirectly, any shares of Common Stock (or any security convertible
into, exercisable for or exchangeable for Common Stock) without the consent of
Bear, Stearns & Co. Inc. for a period of 180 days after the date of this
Prospectus, except that the Company may issue shares of Common Stock upon the
exercise of options granted under its stock option plans. After the expiration
of the "lock-up" agreements, such persons will be entitled to sell, distribute
or otherwise dispose of the Common Stock that they hold subject to the
provisions of applicable securities laws.
The Underwriters are reserving up to 150,000 shares of Common Stock in the
Offering for sales to officers, directors and employees of the Company and their
friends and relatives at the initial public offering price. Any shares of Common
Stock not purchased by those persons will be sold to the general public in the
Offering.
The Representatives have informed the Company that they do not expect sales
to discretionary accounts by the Underwriters to exceed five percent of the
total number of shares of Common Stock offered by them.
Prior to the Offering, there has been no public market for the Common
Stock. The initial public offering price will be determined by negotiation
between the Company and the Representatives. Among the factors which will be
considered in these negotiations are the Company's history, capital structure
and financial condition, its past and present earnings and the trend of such
earnings, prospects for the Company and its industry, the present state of the
Company's development, the recent market prices of publicly-held companies that
the Company and the Representatives believe to be comparable to the Company and
general conditions prevailing in the securities markets at the time of the
Offering.
LEGAL MATTERS
Certain legal matters in connection with the Common Stock being offered
hereby will be passed upon for the Company by Thompson & Knight, P.C., Dallas,
Texas. Certain legal matters will be passed upon for the Underwriters by Vinson
& Elkins L.L.P., Dallas, Texas.
56
<PAGE> 57
EXPERTS
The financial statements of Brigham Oil and Gas, L.P. as of December 31,
1996 and 1995 and for each of the three years in the period ended December 31,
1996 and the Balance Sheet of Brigham Exploration Company as of February 26,
1997 included in this Prospectus have been so included in reliance on the
reports of Price Waterhouse LLP, independent accountants, given on authority of
said firm as experts in auditing and accounting.
The letter of Cawley, Gillespie & Associates, Inc., independent oil and gas
consultants, set forth in this Prospectus as Appendix A has been included herein
in reliance upon the firm as expert with respect to the matters contained in
that letter. In addition, the information with respect to the reserve reports
prepared by Cawley Gillespie has been included herein in reliance upon by the
firm as experts with respect to such information.
AVAILABLE INFORMATION
The Company has filed with the Commission a Registration Statement on Form
S-1 (as amended and together with all exhibits thereto, the "Registration
Statement") under the Securities Act, with respect to the shares of Common Stock
offered by this Prospectus. This Prospectus constitutes a part of the
Registration Statement and does not contain all of the information set forth in
the Registration Statement, certain parts of which are omitted from this
Prospectus as permitted by the rules and regulations of the SEC. Statements in
this Prospectus about the contents of any contract or other document are not
necessarily complete; reference is made in each instance to the copy of the
contract or other document filed as an exhibit to the Registration Statement.
Each such statement is qualified in all respects by such reference. The
Registration Statement and accompanying exhibits and schedules may by inspected
and copies may be obtained (at prescribed rates) at the public reference
facilities of the SEC at Judiciary Plaza, 450 Fifth Street, N.W., Room 1024,
Washington, D.C. 20549. Copies of the Registration Statement may also be
inspected at the SEC's regional offices at 7 World Trade Center, Suite 1300, New
York, New York 10048 and Citicorp Center, 500 West Madison Street, Suite 1400,
Chicago, Illinois 60661-2511. In addition, the Common Stock will be listed on
the Nasdaq National Market, 1735 K Street, N.W., Washington, D.C. 20006-1500,
where such material may also be inspected and copied.
As a result of the Offering, the Company will become subject to the
information and periodic reporting requirements of the Securities Exchange Act
of 1934, and, in accordance therewith, will file periodic reports, proxy
statements and other information with the SEC. Such periodic reports, proxy
statements and other information will be available for inspection and copying at
the public reference facilities and regional offices referred to above. In
addition, these reports, proxy statements and other information may also be
obtained from the web site that the SEC maintains at http://www.sec.gov.
The Company intends to furnish its shareholders annual reports containing
consolidated financial statements certified by its independent auditors and
quarterly reports for each of the first three quarters of each fiscal year
containing unaudited financial information.
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<PAGE> 58
GLOSSARY OF CERTAIN OIL AND GAS TERMS
The following are abbreviations and definitions of certain terms commonly
used in the oil and gas industry and this Prospectus.
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.
Completion. The installation of permanent equipment for the production of
oil or natural gas.
Developed Acreage. The number of acres which are allocated or assignable to
producing wells or wells capable of production.
Development Well. A well drilled within the proved area of an oil or
natural gas reservoir to the depth of a stratigraphic horizon known to be
productive.
Drilling Costs. The costs associated with drilling and completing a well
(exclusive of seismic and land acquisition costs for that well and future
development costs associated with proved undeveloped reserves added by the well)
divided by total proved reserve additions.
Dry Well. A well found to be incapable of producing either oil or natural
gas in sufficient quantities to justify completion of an oil or gas well.
Exploratory Well. A well drilled to find and produce oil or natural gas in
an unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir, or to extend a known reservoir.
Finding and Development Costs. Capital costs incurred in the acquisition,
exploration and development of proved oil and natural gas reserves divided by
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 equivalent.
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 equivalent.
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 or condensate.
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 PV-10. 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
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<PAGE> 59
estimated production and future development costs, using prices and costs as of
the date of estimation without future escalation, without giving effect to
non-property related expenses such as general and administrative expenses, debt
service and depreciation, depletion and amortization, and discounted using an
annual discount rate of 10%.
Proved Developed Reserves. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Proved Reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved Undeveloped Reserves. Reserves that are expected to be recovered
from new wells on undrilled acreage or from existing wells where a relatively
major expenditure is required for recompletion.
Royalty. An interest in an oil and gas lease that gives the owner of the
interest the right to receive a portion of the production from the leased
acreage (or of the proceeds of the sale thereof), but generally does not require
the owner to pay any portion of the costs of drilling or operating the wells on
the leased acreage. Royalties may be either landowner's royalties, which are
reserved by the owner of the leased acreage at the time the lease is granted, or
overriding royalties, which are usually reserved by an owner of the leasehold in
connection with a transfer to a subsequent owner.
Spud. Start drilling a new well (or restart).
Success Rate. The number of wells on which production casing has been run
for a completion attempt as a percentage of the number of wells drilled.
2-D Seismic. The method by which a cross-section of the earth's subsurface
is created through the interpretation of reflecting seismic data collected along
a single source profile.
3-D Seismic. The method by which a three dimensional image of the earth's
subsurface is created through the interpretation of reflection seismic data
collected over surface grid. 3-D seismic surveys allow for a more detailed
understanding of the subsurface than do conventional surveys and contribute
significantly to field appraisal, development and production.
Working Interest. An interest in an oil and gas lease that gives the owner
of the interest the right to drill for and produce natural gas and oil on the
leased acreage and requires the owner to pay a share of the costs of drilling
and production operations.
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<PAGE> 60
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Unaudited Pro Forma Financial Statements of Brigham
Exploration Company....................................... F1-2
Unaudited Pro Forma Balance Sheet......................... F1-3
Unaudited Pro Forma Statement of Operations............... F1-4
Notes to the Unaudited Pro Forma Financial Statements..... F1-5
Balance Sheet of Brigham Exploration Company
Report of Independent Accountants......................... F2-1
Balance Sheet as of February 26, 1997..................... F2-2
Notes to the Balance Sheet................................ F2-3
Financial Statements of Brigham Oil & Gas, L.P.
Report of Independent Accountants......................... F3-1
Balance Sheets as of December 31, 1995 and 1996........... F3-2
Statements of Operations for the Years Ended December 31,
1994, 1995, and 1996................................... F3-3
Statements of Partners' Capital as of December 31, 1994,
1995, and 1996......................................... F3-4
Statements of Cash Flows for the Years Ended December 31,
1994, 1995, and 1996................................... F3-5
Notes to the Financial Statements......................... F3-6
</TABLE>
F1-1
<PAGE> 61
BRIGHAM EXPLORATION COMPANY
(A NEWLY FORMED DELAWARE CORPORATION)
UNAUDITED PRO FORMA FINANCIAL STATEMENTS
The following Unaudited Pro Forma Financial Statements of the Company have
been prepared to give effect to the Exchange described below, the issuance of
employee stock options under the 1997 Incentive Plan and the issuance of Common
Stock pursuant to the Offering (and the application of the estimated net
proceeds therefrom) as if these events had taken place on December 31, 1996 for
purposes of the Unaudited Pro Forma Balance Sheet and as if these events had
taken place on January 1, 1996 for purposes of the Unaudited Pro Forma Statement
of Operations.
Under the Exchange Agreement, effective February 27, 1997, the following
transactions occurred: (i) GAP III and the limited partners of the Partnership
transferred all their partnership interests to the Company in exchange for an
aggregate of 3,314,286 shares of Common Stock, (ii) the stockholders of Brigham,
Inc. transferred all of the issued and outstanding stock of Brigham, Inc. to the
Company in exchange for an aggregate of 3,859,821 shares of Common Stock and
(iii) Resource Investors Management Company ("RIMCO") exchanged all of the 5%
Convertible Unsecured Subordinated Notes of the Partnership for 1,754,464 shares
of Common Stock. These transactions are referred to herein as the "Exchange." As
a result of the Exchange, Brigham Exploration Company owns, directly or
indirectly, all the partnership interests in the Partnership and conducts its
active business operations through the Partnership. No instruments, agreements
or rights exist which may be converted, exchanged into, or otherwise become
interests in the Partnership. Brigham, Inc.'s only asset is its investment in
the Partnership.
The Unaudited Pro Forma Financial Statements of the Company are not
necessarily indicative of the results for the periods presented had the
Exchange, the issuance of employee stock options under the 1997 Incentive Plan
and the issuance of Common Stock pursuant to the Offering (and the application
of the estimated net proceeds therefrom) taken place on January 1, 1996. In
addition, future results may vary significantly from the results reflected in
the accompanying Unaudited Pro Forma Financial Statements because of normal
production declines, changes in product prices, and the success of future
exploration and development activities, among other factors. This information
should be read in conjunction with the Balance Sheet of Brigham Exploration
Company and the Financial Statements of Brigham Oil & Gas, L.P., and the notes
thereto, all included elsewhere herein.
F1-2
<PAGE> 62
BRIGHAM EXPLORATION COMPANY
UNAUDITED PRO FORMA BALANCE SHEET
DECEMBER 31, 1996
(IN THOUSANDS)
<TABLE>
<CAPTION>
PRO FORMA
BRIGHAM OIL PRO FORMA OFFERING PRO FORMA
AND GAS, L.P. ADJUSTMENTS PRO FORMA ADJUSTMENTS AS ADJUSTED
------------- ----------- --------- ----------- -----------
<S> <C> <C> <C> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents...................... $ 1,447 $ -- $ 1,447 $21,570(d) $15,017
(8,000)(e)
Accounts receivable............................ 2,696 -- 2,696 -- 2,696
Prepaid expenses............................... 152 -- 152 -- 152
------- -------- ------- ------- -------
Total current assets..................... 4,295 -- 4,295 13,570 17,865
------- -------- ------- ------- -------
Natural gas and oil properties, at cost, net..... 28,005 -- 28,005 -- 28,005
Other property and equipment, at cost, net....... 532 -- 532 -- 532
Drilling advances paid........................... 419 -- 419 -- 419
Other noncurrent assets.......................... 363 -- 363 -- 363
------- -------- ------- ------- -------
$33,614 $ -- $33,614 $13,570 $47,184
======= ======== ======= ======= =======
LIABILITIES AND PARTNERS' CAPITAL/STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable............................... $ 2,937 $ -- $ 2,937 $ -- $ 2,937
Accrued drilling costs......................... 915 -- 915 -- 915
Participant advances received.................. 1,137 -- 1,137 -- 1,137
Other current liabilities...................... 628 -- 628 -- 628
------- -------- ------- ------- -------
Total current liabilities................ 5,617 -- 5,617 -- 5,617
------- -------- ------- ------- -------
Notes payable.................................... 8,000 -- 8,000 (8,000)(e) --
Subordinated notes payable -- related party...... 16,000 (16,000)(b) -- -- --
Deferred interest payable -- related party....... 433 (433)(b) -- -- --
Other noncurrent liabilities..................... 320 -- 320 -- 320
Deferred income tax liability.................... -- 5,112(a) 5,112 -- 5,112
Partners' capital/stockholders' equity:
Partners' capital:
General partners............................. 3,190 (3,190)(b) -- -- --
Limited partners............................. 54 (54)(b) -- -- --
Stockholders' equity:
Preferred stock, $.01 par value, 10 million
shares authorized.......................... -- -- -- -- --
Common stock, $.01 par value, 30 million
shares authorized.......................... -- 89(b) 89 30(d) 119
Additional paid-in-capital................... -- 19,588(b) 21,520 21,540(d) 43,060
1,932(c)
Unearned stock compensation.................. -- (1,932)(c) (1,932) -- (1,932)
Accumulated deficit.......................... -- (5,112)(a) (5,112) -- (5,112)
------- -------- ------- ------- -------
Total partners' capital/stockholders'
equity................................. 3,244 11,321 14,565 21,570 36,135
------- -------- ------- ------- -------
$33,614 $ -- $33,614 $13,570 $47,184
======= ======== ======= ======= =======
</TABLE>
The Company uses the full cost method to account for its natural gas and oil
properties.
See accompanying notes to the Unaudited Pro Forma Financial Statements.
F1-3
<PAGE> 63
BRIGHAM EXPLORATION COMPANY
UNAUDITED PRO FORMA STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 1996
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
PRO FORMA
BRIGHAM OIL PRO FORMA OFFERING PRO FORMA
AND GAS, L.P. ADJUSTMENTS PRO FORMA ADJUSTMENTS AS ADJUSTED
------------- ----------- --------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Revenues:
Natural gas and oil sales............. $6,141 $ -- $6,141 $ -- $6,141
Workstation revenue................... 627 -- 627 -- 627
------ ------- ------ ------ ------
6,768 -- 6,768 -- 6,768
------ ------- ------ ------ ------
Costs and expenses:
Lease operating....................... 726 -- 726 -- 726
Production taxes...................... 362 -- 362 -- 362
General and administrative............ 2,199 -- 2,199 -- 2,199
Amortization of stock compensation.... -- 344(c) 344 -- 344
Depletion of natural gas and oil
properties......................... 2,323 34(c) 2,357 -- 2,357
Depreciation and amortization......... 487 -- 487 -- 487
------ ------- ------ ------ ------
6,097 378 6,475 -- 6,475
------ ------- ------ ------ ------
Operating income (loss)....... 671 (378) 293 -- 293
------ ------- ------ ------ ------
Other income (expense):
Interest income....................... 52 -- 52 -- 52
Interest expense...................... (373) -- (373) 373(e) --
Interest expense -- related party..... (800) 800(b) -- -- --
------ ------- ------ ------ ------
Net income (loss) before income taxes... (450) 422 (28) 373 345
Income tax benefit (expense)............ -- 97(a) 97 (127)(a) (30)
------ ------- ------ ------ ------
Net income (loss)..................... $ (450) $ 519 $ 69 $ 246 $ 315
====== ======= ====== ====== ======
Net income per common share........... $ 0.01 $ 0.03
====== ======
Weighted average number of common
shares outstanding................. 9,170 12,170
====== ======
</TABLE>
See accompanying notes to the Unaudited Pro Forma Financial Statements.
F1-4
<PAGE> 64
BRIGHAM EXPLORATION COMPANY
NOTES TO THE UNAUDITED PRO FORMA FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION
The accompanying Unaudited Pro Forma Financial Statements of the Company
have been prepared to give effect to the Exchange, the issuance of employee
stock options under the 1997 Incentive Plan and the issuance of Common Stock
pursuant to the Offering (and the application of the estimated net proceeds
therefrom) as if such transactions had taken place on December 31, 1996 for
purposes of the Unaudited Pro Forma Balance Sheet and as if the transactions had
taken place on January 1, 1996 for purposes of the Unaudited Pro Forma Statement
of Operations. The Company was formed in February 1997 with a capitalization of
$30. As the Exchange is the conversion of a partnership to a corporation, the
Exchange has been accounted for as a reorganization.
2. PRO FORMA ADJUSTMENTS AND PRO FORMA OFFERING ADJUSTMENTS
The Unaudited Pro Forma Financial Statements reflect the following pro
forma adjustments related to the consummation of the Exchange, the issuance of
employee stock options under the 1997 Incentive Plan and the issuance of Common
Stock pursuant to the Offering (and the application of the estimated net
proceeds therefrom).
a. To record current and deferred federal income tax expense as if the
Partnership had been a taxable entity.
b. To record (i) the issuance of 3,859,821 shares of Common Stock of the
Company in exchange for all of the issued and outstanding stock of
Brigham, Inc., (ii) the issuance of 3,314,286 shares of Common Stock of
the Company in exchange for all of the partnership interests of the
Partnership's other general partner and its limited partners and (iii)
the issuance of 1,754,464 shares of Common Stock of the Company in
exchange for all of the subordinated notes payable.
c. To record unearned compensation and the amortization thereon related to
employee stock options granted under the 1997 Incentive Plan in March
1997. A portion of the amortization of the unearned compensation was
capitalized as part of the Company's amortizable base of the full cost
pool to the extent that this cost was directly attributable to
acquisition, exploration and development activities. Depletion of
natural gas and oil properties was adjusted accordingly.
d. To reflect the issuance of 3,000,000 shares of Common Stock at the
initial public offering price of $8.00 per share for estimated proceeds
of $21,570,000, net of underwriting discounts and estimated expenses of
this Offering.
e. To record the partial use of the net proceeds of the Offering to fully
repay borrowings under the Revolving Credit Facility.
3. INCOME TAXES
Upon consummation of the Exchange, the Company will record a deferred tax
liability or asset for temporary differences between the financial statement and
tax bases of assets and liabilities at the Exchange date given the provisions of
enacted tax laws. Assuming the Exchange had occurred on December 31, 1996, the
Company would have incurred an estimated charge of $5.1 million to record a
deferred tax liability primarily reflecting the difference between the tax bases
and the financial statement bases of the Partnership's natural gas and oil
properties. As this will be a nonrecurring charge, it has not been included in
the Unaudited Pro Forma Statement of Operations. The ultimate tax bases and
related difference from financial statement bases cannot be ultimately
determined until consummation of the Exchange, and such basis differences will
change depending upon the level and nature of operations and the amount of
taxable income and deductions allocated to the partners through the date of the
Exchange. Such basis differences could vary materially from this estimate.
F1-5
<PAGE> 65
BRIGHAM EXPLORATION COMPANY
NOTES TO THE UNAUDITED PRO FORMA FINANCIAL STATEMENTS -- (CONTINUED)
4. NET LOSS PER COMMON SHARE
Pro forma net loss per common share is presented giving effect to the
number of shares outstanding subsequent to the Exchange (8,928,574 shares) and
giving effect to 644,097 stock options issued under the 1997 Incentive Plan on
February 28, 1997. These options, which have an exercise price of $5.00 per
share, are treated as Common Stock equivalents. The number of equivalent shares
was determined by the treasury stock method based on the offering price of $8.00
per share. In addition to the effect of these events, pro forma, as adjusted,
net loss per common share gives effect to the 3,000,000 shares of Common Stock
issued pursuant to the Offering.
5. STOCK COMPENSATION
In March 1997 the Compensation Committee of the Board of Directors of the
Company granted 644,097 stock options to key employees of the Company. These
options have an exercise price of $5.00 per share, expire in 2004, and will vest
in varying amounts through 2003. In accordance with SFAS 123, the Company has
elected to follow the accounting provisions of Accounting Principles Board
Opinion No. 25 for stock-based compensation and record unearned compensation, a
deduction from stockholders' equity, for the difference between the market value
of the Company's stock on the grant date and the exercise price of the options.
This amount, which the Company estimates will be $1.9 million, will be amortized
over the appropriate vesting period (see Note 2.c).
As provided under SFAS 123, the Company estimates that the fair value of
these options on their grant date, using the Black-Sholes Option Pricing Model,
will be $3.4 million ($5.32 per option). This valuation has been determined
using the following assumptions: risk free interest rate of 6.24%; volatility
factor of the expected market price of the Company's common stock of 38%; no
expected dividends; and weighted average option lives of 7.3 years. If this
valuation method were elected for accounting purposes, the estimated fair value
of $3.4 million would be amortized over the appropriate vesting periods of the
options through 2003, resulting in a pro forma net loss for the year ended
December 31, 1996 of $124,000, or $0.01 per common share, and pro forma, as
adjusted, net income of $122,000, or $0.01 per common share.
F1-6
<PAGE> 66
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors
and Stockholders of Brigham Exploration Company
In our opinion, the accompanying balance sheet presents fairly, in all
material respects, the financial position of Brigham Exploration Company at
February 26, 1997, in conformity with generally accepted accounting principles.
This balance sheet is the responsibility of the Company's management; our
responsibility is to express an opinion on the balance sheet based on our audit.
We conducted our audit in accordance with generally accepted auditing standards
which require that we plan and perform the audit to obtain reasonable assurance
about whether the balance sheet is free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the balance sheet, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial
statement presentation. We believe that our audit provides a reasonable basis
for the opinion expressed above.
PRICE WATERHOUSE LLP
Houston, Texas
February 26, 1997, except as to Notes 1 and 3,
which are as of February 27, 1997
F2-1
<PAGE> 67
BRIGHAM EXPLORATION COMPANY
(A NEWLY FORMED DELAWARE CORPORATION)
BALANCE SHEET
FEBRUARY 26, 1997
<TABLE>
<S> <C>
Assets:
Cash.................................. $30
===
Stockholders' equity:
Preferred stock, $.01 par value, 10
million shares authorized, none
issued and outstanding............. $--
Common stock, $.01 par value, 30
million shares authorized, 3 shares
issued and outstanding............. --
Additional paid-in capital............ 30
---
Total stockholders' equity.... $30
===
</TABLE>
See accompanying notes to the balance sheet.
F2-2
<PAGE> 68
BRIGHAM EXPLORATION COMPANY
(A NEWLY FORMED DELAWARE CORPORATION)
NOTES TO THE BALANCE SHEET
FEBRUARY 26, 1997
1. ORGANIZATION AND BUSINESS PURPOSE
Brigham Exploration Company (the "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 partners' interests in Brigham Oil &
Gas, L.P. (the "Partnership"). Subsequent to the Exchange, which occurred on
February 27, 1997, the Company and its subsidiary hold all Partnership
interests. Additionally, the Company exchanged shares with the holder of the
Partnership's subordinated convertible notes which would otherwise be
convertible into a 19.65% interest in the Partnership. 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 the Exchange is the conversion of a partnership into a
corporation, the Exchange has been accounted for as a reorganization.
The Company expects to initiate a public issuance of common stock in early
1997.
2. STOCKHOLDERS' EQUITY
The Board of Directors of the Company is empowered, without approval of
stockholders, to cause shares of preferred stock to be issued in one or more
series. The Board of Directors is authorized to fix and determine variations in
designations, preferences and relative, participating, optional or other special
rights and the limitations or restrictions of such rights and voting powers.
Holders of common stock are entitled to one vote per share in the election
of directors and on all other matters submitted to a vote of common
stockholders. The common stock does not have cumulative voting rights. Holders
of common stock are entitled to receive dividends, if any, as may be declared by
the Board of Directors out of funds legally available therefore, subject to any
preferential dividend rights of holders of outstanding preferred stock.
3. STOCK COMPENSATION
The Board of Directors and stockholders of the Company anticipate the
adoption of an incentive plan, to be effective upon completion of the Exchange,
which will provide for the issuance of stock options, stock appreciation rights,
stock, restricted stock, cash or any combination of the foregoing. The objective
of this plan will be to reward key employees whose performance may have a
significant effect on the success of the Company. 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.
An aggregate of 1,588,169 shares of common stock will be reserved for issuance
pursuant to this plan with 644,097 shares subject to initial grants of stock
options at an exercise price of $5.00 per share. The Company estimates that the
fair value of these options on their grant date, using the Black-Scholes
option-pricing model, will be $3.4 million. In accordance with SFAS No. 123, the
Company has elected to follow the accounting provisions of Accounting Principles
Board Opinion No. 25 for stock-based compensation and record unearned
compensation, a deduction from stockholders' equity, for the difference between
the market value of the Company's stock on the grant date and the exercise price
of the options. This amount, which the Company estimates will be $1.9 million,
will be amortized over the appropriate vesting period.
The Board of Directors and stockholders of the Company also anticipate the
adoption of the 1997 Director Stock Option Plan, pursuant to which each newly
elected nonemployee director shall be granted an option to purchase 1,000 shares
of common stock and each nonemployee director will receive an option to purchase
500 shares of common stock on December 31 of each year. An aggregate of 25,000
shares of common stock will be reserved for issuance pursuant to this plan. The
exercise price of options granted under
F2-3
<PAGE> 69
this plan will be equal to the fair market value of the underlying common stock
on the date of grant. No compensation expense will result from options granted
under this plan.
On February 27, 1997, in connection with the Exchange (see Note 1), three
employees who had been granted restricted interests in the Partnership in 1994
transferred, upon the initial filing of a registration statement with the SEC
for a public offering of common stock, these partnership interests to the
Company in exchange for 156,250 shares of restricted common stock. The terms of
the restricted stock and the restricted partnership interests are substantially
the same. The shares vest over a three year period ending in 1999. No
compensation expense will result from this exchange.
F2-4
<PAGE> 70
REPORT OF INDEPENDENT ACCOUNTANTS
To the Partners of
Brigham Oil & Gas, L.P.
In our opinion, the accompanying balance sheets and the related statements
of operations, of partners' capital and of cash flows present fairly, in all
material respects, the financial position of Brigham Oil & Gas, L.P. at December
31, 1996 and 1995, and the results of its operations and its cash flows for each
of the three years in the period ended December 31, 1996, in conformity with
generally accepted accounting principles. These financial statements are the
responsibility of the Partnership's management; our responsibility is to express
an opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted auditing
standards which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
PRICE WATERHOUSE LLP
Houston, Texas
February 26, 1997, except as to Notes 1 and 4,
which are as of February 27, 1997
F3-1
<PAGE> 71
BRIGHAM OIL & GAS, L.P.
BALANCE SHEETS
(IN THOUSANDS)
<TABLE>
<CAPTION>
DECEMBER 31,
------------------
1995 1996
------- -------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents............. $ 1,802 $ 1,447
Accounts receivable................... 1,256 2,696
Prepaid expenses...................... 177 152
------- -------
Total current assets.......... 3,235 4,295
------- -------
Natural gas and oil properties, at cost,
net (including $3,460 and $7,068,
respectively, not subject to
depletion)............................ 18,538 28,005
Other property and equipment, at cost,
net................................... 684 532
Drilling advances paid.................. 127 419
Other noncurrent assets................. 332 363
------- -------
$22,916 $33,614
======= =======
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable...................... $ 1,318 $ 2,937
Accrued drilling costs................ 588 915
Participant advances received......... 333 1,137
Other current liabilities............. 689 628
------- -------
Total current liabilities..... 2,928 5,617
------- -------
Notes payable........................... -- 8,000
Subordinated notes payable -- related
party................................. 16,000 16,000
Deferred interest payable -- related
party................................. 113 433
Other noncurrent liabilities............ 181 320
Commitments and contingencies
Partners' capital:
General partners...................... 3,620 3,190
Limited partners...................... 74 54
------- -------
Total partners' capital....... 3,694 3,244
------- -------
$22,916 $33,614
======= =======
</TABLE>
The Partnership uses the full cost method to account for its natural gas and oil
properties.
See accompanying notes to the financial statements.
F3-2
<PAGE> 72
BRIGHAM OIL & GAS, L.P.
STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------
1994 1995 1996
------- ------- ------
<S> <C> <C> <C>
Revenues:
Natural gas and oil sales................................. $ 2,565 $ 3,578 $6,141
Workstation revenue....................................... 815 635 627
------- ------- ------
3,380 4,213 6,768
------- ------- ------
Costs and expenses:
Lease operating........................................... 491 761 726
Production taxes.......................................... 126 165 362
General and administrative................................ 1,785 1,897 2,199
Depletion of natural gas and oil properties............... 1,104 1,626 2,323
Depreciation and amortization............................. 561 533 487
------- ------- ------
4,067 4,982 6,097
------- ------- ------
Operating income (loss)........................... (687) (769) 671
------- ------- ------
Other income (expense):
Interest income........................................... 56 128 52
Interest expense.......................................... (76) (187) (373)
Interest expense -- related party......................... (592) (749) (800)
------- ------- ------
Net loss.......................................... $(1,299) $(1,577) $ (450)
======= ======= ======
Unaudited pro forma information (Notes 1 and 2)
Net loss.................................................. $ (450)
Pro forma Exchange adjustments............................ 422
------
Pro forma net loss before taxes........................... (28)
Pro forma income tax benefit.............................. 97
------
Pro forma net income...................................... $ 69
======
Pro forma net income per common share..................... $ 0.01
======
Pro forma weighted average number of common shares
outstanding............................................ 9,170
======
</TABLE>
See accompanying notes to the financial statements.
F3-3
<PAGE> 73
BRIGHAM OIL & GAS, L.P.
STATEMENTS OF PARTNERS' CAPITAL
(IN THOUSANDS)
<TABLE>
<CAPTION>
GENERAL LIMITED
PARTNERS PARTNERS TOTAL
-------- -------- -------
<S> <C> <C> <C>
Balance at December 31, 1993................................ $ 6,364 $206 $ 6,570
Net loss.......................................... (1,239) (60) (1,299)
------- ---- -------
Balance at December 31, 1994................................ 5,125 146 5,271
Net loss.......................................... (1,505) (72) (1,577)
------- ---- -------
Balance at December 31, 1995................................ 3,620 74 3,694
Net loss.......................................... (430) (20) (450)
------- ---- -------
Balance at December 31, 1996................................ $ 3,190 $ 54 $ 3,244
======= ==== =======
</TABLE>
See accompanying notes to the financial statements.
F3-4
<PAGE> 74
BRIGHAM OIL & GAS, L.P.
STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------
1994 1995 1996
------- -------- --------
<S> <C> <C> <C>
Cash flows from operating activities:
Net loss.................................................. $(1,299) $ (1,577) $ (450)
Adjustments to reconcile net loss to cash provided by
operating activities:
Depletion of natural gas and oil properties............ 1,104 1,626 2,323
Depreciation and amortization.......................... 561 533 487
Changes in working capital and other items:
(Increase) decrease in accounts receivable........... 2,074 413 (1,440)
(Increase) decrease in prepaid expenses.............. (29) (107) 25
Increase (decrease) in accounts payable.............. (1,451) 128 1,619
Increase (decrease) in participant advances
received.......................................... (170) 92 804
Increase (decrease) in other current liabilities..... (121) 151 60
Increase in deferred interest payable -- related
party............................................. -- 113 320
Other noncurrent assets.............................. (43) (26) (224)
Other noncurrent liabilities......................... -- 37 186
------- -------- --------
Net cash provided by operating activities......... 626 1,383 3,710
------- -------- --------
Cash flows from investing activities:
Additions to natural gas and oil properties............... (5,445) (7,935) (13,612)
Proceeds from the sale of natural gas and oil
properties............................................. -- -- 2,149
Additions to other property and equipment................. (62) (51) (41)
(Increase) decrease in drilling advances paid............. 44 (19) (292)
------- -------- --------
Net cash used by investing activities............. (5,463) (8,005) (11,796)
------- -------- --------
Cash flows from financing activities:
Proceeds from issuance of subordinated notes payable...... -- 16,000 --
Increase in notes payable................................. 4,950 2,560 8,000
Repayment of notes payable................................ -- (10,510) --
Principal payments on capital lease obligations........... (316) (326) (269)
------- -------- --------
Net cash provided by financing activities......... 4,634 7,724 7,731
------- -------- --------
Net increase (decrease) in cash and cash equivalents........ (203) 1,102 (355)
Cash and cash equivalents, beginning of year................ 903 700 1,802
------- -------- --------
Cash and cash equivalents, end of year...................... $ 700 $ 1,802 $ 1,447
======= ======== ========
Supplemental disclosure of cash flow information:
Cash paid during the period for interest.................. $ 667 $ 654 $ 762
======= ======== ========
Supplemental disclosure of noncash investing and financing
activities:
Capital lease asset additions............................. $ 361 $ 208 $ 101
======= ======== ========
</TABLE>
See accompanying notes to the financial statements.
F3-5
<PAGE> 75
BRIGHAM OIL & GAS, L.P.
NOTES TO THE FINANCIAL STATEMENTS
1. ORGANIZATION AND NATURE OF OPERATIONS
Brigham Oil & Gas, L.P. (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 in the Permian and Hardeman Basins of West Texas, the Anadarko Basin
and the Gulf Coast.
Brigham, Inc. is the managing general partner of the Partnership and owned
a 54% interest in the Partnership. Brigham, Inc. generally directs all
activities of the Partnership. Until February 27, 1997, the other general
partner held a 38% interest in the Partnership, had participating rights in
certain Major Decisions, as defined, and had a preference in the allocation of
profits and other items.
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 for a public offering of
common stock, the shareholders of Brigham, Inc. transferred all of the
outstanding stock of Brigham, Inc. to a newly formed entity, Brigham Exploration
Company (the "Company"), in exchange for shares of common stock of the Company.
Brigham, Inc. is a Texas corporation whose only asset is its ownership interest
in the Partnership. 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 shares of common stock of
the new entity. Furthermore, the holders of the subordinated convertible notes
(see Note 4) transferred these notes to the Company in exchange for shares of
common stock. As a result of these transactions, hereafter referred to as the
"Exchange," the Company now owns all the partnership interests in the
Partnership.
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.
Cash and Cash Equivalents
The Partnership considers all highly liquid financial instruments with an
original maturity of three months or less to be cash equivalents.
Property and Equipment
The Partnership 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 leasehold acquisition costs,
geological and geophysical expenditures, dry hole costs and tangible and
intangible development costs, incurred for the purpose of finding natural gas
and oil reserves are capitalized. Included in the Partnership's investment in
natural gas and oil properties as of December 31, 1994, 1995 and 1996 are
general and administrative costs of $1,320,114, $1,640,196 and $1,826,013,
respectively. These capitalized general and administrative costs consist
primarily of the compensation and benefit costs of exploration department
personnel which are directly attributable to the Partnership's acquisition,
exploration and development activities. Other internal costs (primarily
including office rent and technical computer maintenance and support) are
capitalized to the extent they are attributable to the Partnership's natural gas
and oil property acquisition and exploration activities and would not otherwise
be incurred if such activities were not being undertaken.
F3-6
<PAGE> 76
BRIGHAM OIL & GAS, L.P.
NOTES TO THE FINANCIAL STATEMENTS -- (CONTINUED)
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 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 depletion, 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. The Partnership's only
active cost center since inception has been the United States of America. 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 ceiling test 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 of 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.
Effective January 1, 1996, the Partnership conformed its accounting policy
for the full cost method of accounting to that permitted by Rule 4-10 of the
Security and Exchange Commission's Regulation S-X. The financial statements of
prior years have been restated to apply the new accounting policy retroactively.
The accounting change reduced the Partnership's net loss as previously reported
in 1994 and 1995 by $1,186,005 and $1,389,840, respectively.
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:
<TABLE>
<S> <C>
Furniture and fixtures.................. 10 years
Machinery and equipment................. 5 years
3-D seismic interpretation workstations
and software.......................... 3 years
</TABLE>
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
Joint interest owners may take more or less than their ownership interest
of natural gas volumes from jointly owned reservoirs. The Partnership follows
the sales method of accounting for imbalances. Under this method, the
Partnership records a liability if its sales of natural gas volumes in excess of
its entitlements from a jointly owned reservoir exceed its interest in the
remaining estimated natural gas reserves of such reservoir. Volumetric
production is monitored to minimize imbalances, and such imbalances as of
December 31, 1994, 1995 and 1996 were not significant.
Net realized gains or losses arising from the Partnership's crude oil price
swaps (see Note 7) are recognized in the period incurred as a component of
natural gas and oil sales.
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.
F3-7
<PAGE> 77
BRIGHAM OIL & GAS, L.P.
NOTES TO THE FINANCIAL STATEMENTS -- (CONTINUED)
Federal and State Income Taxes
The financial statements include only those assets, liabilities and
operations that relate to the business of the Partnership. The financial
statements do not include any assets, liabilities or operations attributable to
the partners' individual activities. No provision has been made for income taxes
since these taxes are the responsibility of the partners.
Upon consummation of the Exchange, the Company will record a deferred tax
liability or asset for temporary differences between the financial statement and
tax bases of assets and liabilities at the Exchange date given the provisions of
enacted tax laws. Assuming the Exchange had occurred on December 31, 1996, the
Company would have incurred an estimated charge of $5.1 million to record a
deferred tax liability primarily reflecting the difference between the tax bases
and the financial statement bases of the Partnership's natural gas and oil
properties. The ultimate tax bases and related difference from financial
statement bases have not been determined and such basis differences will change
depending upon the level and nature of operations and the amount of taxable
income and deductions allocated to the partners through the date of the
Exchange. Such basis differences could vary materially from this estimate.
Unaudited Pro Forma Information
The Partnership's legal form has no relation to the capital structure of
the Company after the Exchange. As a result, historical loss per unit amounts
are not relevant and have not been presented.
Pro forma net loss for the year ended December 31, 1996 reflects the
Exchange, including income taxes that would have been recorded had the
Partnership been a taxable entity. Pro forma exchange adjustments primarily
represent the amortization of the compensation expense related to employee stock
options granted upon the formation of the Company (see Note 8), and the
reduction of interest expense related to the transfer of the subordinated notes
payable to the Company as part of the Exchange. Pro forma income taxes have been
included in the Statement of Operations pursuant to the rules and regulations of
the SEC for instances when a partnership becomes subject to federal income
taxes.
Pro forma net loss per common share is presented giving effect to the
number of shares outstanding subsequent to the Exchange (8,928,574 shares) and
giving effect to the shares to be issued under the anticipated February 1997
employee stock option grants (see Note 8). Pro forma net loss per common share
was calculated using the treasury stock method.
Reclassification of Prior Years
Prior year financial statements have been reclassified to conform to 1996
presentations.
F3-8
<PAGE> 78
BRIGHAM OIL & GAS, L.P.
NOTES TO THE FINANCIAL STATEMENTS -- (CONTINUED)
3. PROPERTY AND EQUIPMENT
Property and equipment, at cost, are summarized as follows (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
------------------
1995 1996
------- -------
<S> <C> <C>
Natural gas and oil properties.......... $25,765 $37,555
Accumulated depletion................... (7,227) (9,550)
------- -------
18,538 28,005
------- -------
Other property and equipment:
3-D seismic interpretation
workstations and software.......... 1,351 1,456
Office furniture and equipment........ 347 384
Accumulated depreciation.............. (1,014) (1,308)
------- -------
684 532
------- -------
$19,222 $28,537
======= =======
</TABLE>
On January 30, 1996, the Partnership sold its interest in certain producing
properties for $2.1 million. A gain or loss was not recognized on this
transaction because the Partnership applies the full cost method of accounting
for its investment in natural gas and oil properties.
4. NOTES PAYABLE AND SUBORDINATED NOTES PAYABLE
The notes payable pertain to a revolving credit facility, due 1999, entered
into by the Partnership in April 1996. This facility provides for borrowings up
to $25 million and is secured by the Partnership's natural gas and oil
properties. The Partnership's borrowings under the revolving credit facility are
limited to a borrowing base determined semiannually by the lender. This
determination is based upon the Partnership's proved natural gas and oil
properties.
The amounts outstanding under the revolving credit facility bear interest,
at the borrower's option, at the Base Rate or (i) LIBOR plus 1.75% if the
principal outstanding is less than or equal to 50% of the borrowing base, (ii)
LIBOR plus 2.0% if the principal outstanding is less than or equal to 75% but
more than 50% of the borrowing base, and (iii) LIBOR plus 2.25% if the principal
outstanding is greater than 75% of the borrowing base. The Base Rate is the
fluctuating of interest per annum established from time to time by the lender.
The Company also pays a quarterly commitment fee of 0.5% per annum for the
unused portion of the borrowing base.
The Company is subject to certain covenants under the terms of the
revolving credit facility. The financial ratios that the Partnership was
required to meet at December 31, 1996 were as follows: (i) the ratio of current
assets, as defined in the borrowing agreement, to current liabilities must be at
least 1.0 to 1.0, and (ii) the debt service coverage ratio of net cash flow to
debt service for the three months ended December 31, 1996 must be at least 2.25
to 1.0. The revolving credit facility contains certain other affirmative and
negative covenants, including limitations on additional indebtedness and
restrictions on the payment of dividends. The Partnership is currently in
compliance with all covenants.
The subordinated notes payable bear interest at 5% per annum and are due in
2002. The notes are convertible into a 19.65% interest in the Partnership at any
time prior to maturity and are unsecured. A representative of the holders of
these notes is a member of the Partnership's management committee. Interest
payments of 3% are due semi-annually and the remaining 2% is deferred until
maturity. As part of the Exchange (see Note 1), the holders of these notes
exchanged the notes for shares of the Company's common stock.
F3-9
<PAGE> 79
BRIGHAM OIL & GAS, L.P.
NOTES TO THE FINANCIAL STATEMENTS -- (CONTINUED)
5. CAPITAL LEASE OBLIGATIONS
Property under capital leases consists of the following (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
--------------
1995 1996
----- -----
<S> <C> <C>
3-D seismic interpretation workstations
and software.......................... $ 668 $ 525
Office furniture and equipment.......... 58 17
----- -----
726 542
Accumulated depreciation and
amortization.......................... (324) (305)
----- -----
$ 402 $ 237
===== =====
</TABLE>
The obligations under capital leases are at fixed interest rates ranging
from 11% to 17% 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, 1996 are as follows (in
thousands):
<TABLE>
<S> <C>
1997........................................................ $ 204
1998........................................................ 105
1999........................................................ 28
-----
Total minimum lease payments................................ 337
Estimated executory costs included in capital leases........ (74)
-----
Net minimum lease payments.................................. 263
Amounts representing interest............................... (32)
-----
Present value of net minimum lease payments................. 231
Less: current portion....................................... (133)
-----
Noncurrent portion.......................................... $ 98
=====
</TABLE>
6. COMMITMENTS AND CONTINGENCIES
The Partnership 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 Partnership.
The Partnership leases office equipment and space under operating leases
expiring at various dates through 2007. The future minimum annual rental
payments under the noncancelable terms of these leases at December 31, 1996, are
as follows (in thousands):
<TABLE>
<S> <C>
1997........................................................ $ 526
1998........................................................ 610
1999........................................................ 610
2000........................................................ 543
2001........................................................ 543
Thereafter.................................................. 272
------
$3,104
======
</TABLE>
The Partnership has an option to cancel an office space lease at July 1,
2002. Additional rental payments of $2.6 million will be required for years 2002
through 2007 if the Partnership does not elect to cancel the lease.
F3-10
<PAGE> 80
BRIGHAM OIL & GAS, L.P.
NOTES TO THE FINANCIAL STATEMENTS -- (CONTINUED)
Rental expense for the years ended December 31, 1994, 1995 and 1996 was
$202,923, $239,715 and $253,112, respectively.
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.
As of December 31, 1996, there were no known environmental or other
regulatory matters related to the Partnership's operations which are reasonably
expected to result in a material liability to the Partnership. Compliance with
environmental laws and regulations has not had, and is not expected to have, a
material adverse effect on the Partnership's capital expenditures, earnings or
competitive position.
During 1996, approximately 16%, 12% and 10% of the Partnership's natural
gas and oil production was sold to three separate customers. During 1995,
approximately 14%, 11%, 10%, and 10% of the Partnership's natural gas and oil
production was sold to four separate customers. During 1994, approximately 15%,
15%, 13%, 13%, and 11% of the Partnership's natural gas and oil production was
sold to five separate customers. However, due to the availability of other
markets, the Partnership does not believe that the loss of any one of these
individual customers would adversely affect the Partnership's result of
operations.
7. FINANCIAL INSTRUMENTS
The Partnership periodically enters into crude oil 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
crude oil without the exchange of the underlying crude oil 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 crude oil
prices. Crude oil price swaps are effective in minimizing these risks by
creating essentially equal and offsetting market exposures. The derivative
financial instruments held by the Partnership are not leveraged and are held for
purposes other than trading.
At December 31, 1996, the Partnership was a party to crude oil price swap
based on an average notional volume of 7,550 barrels of crude oil per month and
a fixed price of $22.70 per barrel. The contract expires in May 1997. The fair
market value of the crude oil price swap at December 31, 1996, based on the
market price of crude oil in December 1996, was $41,902.
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 (see Note 4)
approximates its fair market value since it bears interest at floating market
interest rates. At December 31, 1996, the carrying amount of the Partnership's
subordinated notes payable exceeded the fair market value by $1.9 million, based
on current rates offered to the Partnership for debt of the same remaining
maturity.
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, 1996 do not represent significant credit risks as they are
dispersed across many counterparties. Counterparties to the crude oil price
swaps are investment grade financial institutions. Accordingly, the Partnership
does not anticipate any material effect on its financial position or results of
operations as a result of nonperformance by the third parties on the crude oil
price swaps.
F3-11
<PAGE> 81
BRIGHAM OIL & GAS, L.P.
NOTES TO THE FINANCIAL STATEMENTS -- (CONTINUED)
8. EMPLOYEE BENEFIT PLANS
Retirement Savings Plan
During 1996 the Partnership 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
Partnership may, at its discretion, match employee contributions. The
Partnership did not match employee contributions in 1996.
Stock Compensation
The Board of Directors and stockholders of the Company (see Note 1)
anticipate the adoption of an incentive plan, to be effective upon completion of
the Exchange (see Note 1), which will provide for the issuance of stock options,
stock appreciation rights, stock, restricted stock, cash or any combination of
the foregoing. The objective of this plan will be to reward key employees whose
performance may have a significant effect on the success of the Company. An
aggregate of 1,588,169 shares of the Company's common stock will be 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.
The Company's Board of Directors also anticipates that it will grant
644,097 stock options prior to the completion of the proposed initial public
offering (see Note 1). These options will be granted under the incentive plan
established as part of the Exchange and will have an exercise price less than
the public offering price. This grant will result in noncash compensation
expense which will be recognized over the appropriate vesting period.
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 Agreement (see Note 1), the three employees agreed to
transfer, upon the initial filing in early 1997 of a Registration Statement with
the SEC for a public offering of common stock, these partnership 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 partnership
interests are substantially the same. The shares vest over a three-year period
ending in 1999. No compensation expense will result from this exchange.
9. RELATED PARTY TRANSACTIONS
During the years ended December 31, 1994, 1995 and 1996, the Partnership
paid approximately $310,000, $382,000 and $596,000, respectively, in fees for
land acquisition services performed by a company owned by a brother of the
Partnership's President and Chief Executive Officer. Other participants in the
Partnership's 3-D seismic projects reimbursed the partnership for most of these
amounts.
The Partnership also participates in various industry projects with
affiliates of the holder of the subordinated notes payable (see Note 4). During
1995 and 1996, the Partnership received approximately $25,000 and $123,000,
respectively, for workstation time and geoscientists' time spent interpreting
3-D seismic data and workstation use. In addition, the Partnership sold to an
affiliate of the holders of the subordinated notes payable an interest in (i) a
3-D project for approximately $525,000 in 1994, (ii) a 3-D project for
approximately $75,000 in 1995 and (iii) two 3-D delineated potential drilling
locations and 3-D seismic data for approximately $83,000 in 1996.
In 1995 and 1996, the Partnership paid $35,000 and $110,000 for working
interests in natural gas and oil properties owned by affiliates of a member of
the Partnership's management committee. The Partnership
F3-12
<PAGE> 82
BRIGHAM OIL & GAS, L.P.
NOTES TO THE FINANCIAL STATEMENTS -- (CONTINUED)
billed the affiliates $201,000, $13,000 and $68,000 in 1994, 1995 and 1996,
respectively, for their proportionate share of the costs related to this
project.
A limited partner and member of the Partnership's management committee
served as a consultant to the Partnership on various aspects of the
Partnership's business and strategic issues. Fees paid for these services by the
Partnership were $72,000 for each of the twelve month periods ended December 31,
1994 and 1995 and $79,200 for the twelve month period ended December 31, 1996.
10. 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)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------
1994 1995 1996
------ ------ ------
<S> <C> <C> <C>
Natural gas and oil sales.................................. $2,565 $3,578 $6,141
Costs and expenses:
Lease operating.......................................... 491 761 726
Production taxes......................................... 126 165 362
Depletion of natural gas and oil properties.............. 1,104 1,626 2,323
------ ------ ------
Total costs and expenses................................... 1,721 2,552 3,411
------ ------ ------
$ 844 $1,026 $2,730
====== ====== ======
Depletion per physical unit of production (equivalent Mcf
of gas).................................................. $ 1.10 $ 1.22 $ 1.13
====== ====== ======
</TABLE>
Natural gas and oil sales reflect the market prices of net production sold
or transferred, with appropriate adjustments for royalties, net profits interest
and other contractual provisions. Lease operating expenses include lifting costs
incurred to operate and maintain productive wells and related equipment,
including such costs as operating labor, repairs and maintenance, materials,
supplies and fuel consumed. Production taxes include production and severance
taxes. No provision has been made for income taxes since these taxes are the
responsibility of the partners (see Note 2). Depletion of natural gas and oil
properties relates to capitalized costs incurred in acquisition, exploration and
development activities. Results of operations do not include interest expense
and general corporate amounts.
Costs Incurred and Capitalized Costs
The costs incurred in natural gas and oil acquisition, exploration and
development activities follow (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
------------------
1995 1996
------- -------
<S> <C> <C>
Costs incurred for the year:
Exploration............................................... $ 6,893 $10,527
Property acquisition...................................... 1,885 6,195
Development............................................... 713 1,328
Proceeds from participants................................ (1,296) (4,111)
------- -------
$ 8,195 $13,939
======= =======
</TABLE>
F3-13
<PAGE> 83
BRIGHAM OIL & GAS, L.P.
NOTES TO THE FINANCIAL STATEMENTS -- (CONTINUED)
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.
Capitalized costs related to natural gas and oil acquisition, exploration
and development activities follow (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
------------------
1995 1996
------- -------
<S> <C> <C>
Cost of natural gas and oil properties at year-end:
Proved.................................................... $22,305 $30,487
Unproved.................................................. 3,460 7,068
------- -------
Total capitalized costs................................... 25,765 37,555
Accumulated depletion..................................... (7,227) (9,550)
------- -------
$18,538 $28,005
======= =======
</TABLE>
Following is a summary of costs (in thousands) excluded from depletion at
December 31, 1996, 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.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------
PRIOR YEARS 1994 1995 1996 TOTAL
----------- ----- ----- ------- ------
<S> <C> <C> <C> <C> <C>
Property acquisition................... $1,418 $434 $694 $2,515 $5,061
Exploration............................ 480 51 234 1,242 2,007
------ ---- ---- ------ ------
Total.................................. $1,898 $485 $928 $3,757 $7,068
====== ==== ==== ====== ======
</TABLE>
11. 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.
F3-14
<PAGE> 84
BRIGHAM OIL & GAS, L.P.
NOTES TO THE FINANCIAL STATEMENTS -- (CONTINUED)
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.
<TABLE>
<CAPTION>
NATURAL GAS OIL
(MMCF) (MBBLS)
----------- -------
<S> <C> <C>
Proved reserves at December 31, 1993.... 227 336
Revisions to previous estimates....... 102 (26)
Extensions, discoveries and other
additions.......................... 3,415 852
Production............................ (165) (140)
------ -----
Proved reserves at December 31, 1994.... 3,579 1,022
Revisions to previous estimates....... (1,600) (214)
Extensions and discoveries............ 2,555 1,055
Sales of minerals-in-place............ (6) (14)
Production............................ (271) (177)
------ -----
Proved reserves at December 31, 1995.... 4,257 1,672
Revisions of previous estimates....... (1,005) (232)
Extensions, discoveries and other
additions.......................... 7,742 996
Purchase of minerals-in-place......... 260 3
Sales of minerals-in-place............ (299) (272)
Production............................ (698) (227)
------ -----
Proved reserves at December 31, 1996.... 10,257 1,940
====== =====
Proved developed reserves at December
31:
1994.................................. 1,849 915
1995.................................. 3,819 1,274
1996.................................. 6,034 1,453
</TABLE>
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.
F3-15
<PAGE> 85
BRIGHAM OIL & GAS, L.P.
NOTES TO THE FINANCIAL STATEMENTS -- (CONTINUED)
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.
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------
1994 1995 1996
------- -------- --------
<S> <C> <C> <C>
Future cash inflows..................... $22,544 $ 38,333 $ 84,987
Future development and production
costs................................. (8,148) (12,543) (20,998)
------- -------- --------
Future net cash inflows................. $14,396 $ 25,790 $ 63,989
======= ======== ========
Standardized measure of future net cash
inflows discounted at 10% per annum... $10,240 $ 18,222 $ 44,506(1)
======= ======== ========
</TABLE>
- ---------------
(1) The earnings of the Partnership are not subject to income taxes as the
Partnership is a non-taxpaying entity (see Note 2). Once the Partnership
consummates the proposed Exchange (see Note 1), the successor entity will be
a taxable corporation. The estimated pro forma income taxes, discounted at
10%, are approximately $12,146,000 as of December 31, 1996, resulting in pro
forma discounted net cash flows of approximately $32,360,000 as of December
31, 1996.
The average natural gas and oil prices used to calculate the future net
cash inflows at December 31, 1996 were $3.62 per Mcf and $24.66 per barrel,
respectively. At December 31, 1996 and February 14, 1997, respectively, the
NYMEX price for oil was $25.92 per barrel and $22.41 per barrel and the NYMEX
price for natural gas was $2.76 per MMBtu and $1.97 per MMBtu.
Changes in the future net cash inflows (in thousands) discounted at 10% per
annum follow:
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------
1994 1995 1996
------- ------- -------
<S> <C> <C> <C>
Beginning of period..................... $ 3,158 $10,240 $18,222
Sales of natural gas and oil produced,
net of production costs............ (1,948) (2,652) (5,053)
Development costs incurred............ 69 169 246
Extensions and discoveries............ 9,124 11,669 29,457
Purchases of minerals-in-place........ -- -- 384
Sales of minerals-in-place............ -- (198) (2,380)
Net change in prices and production
costs.............................. 139 1,394 7,023
Change in future development costs.... (619) 419 303
Changes in production rates and
other.............................. 36 (364) (342)
Revisions of quantity estimates....... (130) (3,479) (5,176)
Accretion of discount................. 411 1,024 1,822
------- ------- -------
End of period........................... $10,240 $18,222 $44,506
======= ======= =======
</TABLE>
F3-16
<PAGE> 86
APPENDIX A
February 14, 1997
Mr. Jon L. Glass
Brigham Oil & Gas, L.P.
5949 Sherry Lane, Suite 1616
Dallas, Texas 75225
Re: Evaluation
BRIGHAM OIL & GAS, L.P. INTERESTS
Proved Reserves
As of December 31, 1996
Pursuant to the Guidelines of the Securities and
Exchange Commission for Reporting Partnership
Reserves and Future Net Revenue
Dear Mr. Glass:
As requested, we are submitting our estimated proven reserves and future
net cash flows, as of December 31, 1996, attributable to the interests of
Brigham Oil & Gas, L.P. in certain oil and natural gas properties. The evaluated
properties are located in various counties in Kansas, New Mexico, Oklahoma and
Texas. This report was prepared using constant prices and costs and conforms to
the guidelines of the Securities and Exchange Commission (SEC).
Composite forecasts for the total proved, proved developed producing,
proved developed non-producing and proved undeveloped estimates are presented by
category in the accompanying Tables I-P, I-PDP, I-PDNP and I-PUD, respectively.
The estimated net proved reserves and future net cash flow for all three
categories are summarized as follows:
<TABLE>
<CAPTION>
NET RESERVES FUTURE NET CASH FLOW
-------------------------------------- -------------------------------------
OIL GAS PRESENT WORTH
CATEGORY (BARRELS) (MCF) TOTAL AT 10%
-------- ---------------- ------------------ -------------------- -------------
<S> <C> <C> <C> <C>
Proved Developed:
Producing...................... 1,293,456 4,880,441 $38,532,070 $28,543,340
Non-Producing.................. 159,238 1,153,825 5,649,492 2,395,028
Proved Undeveloped............. 487,216 4,222,257 19,806,950 13,567,850
--------- ---------- ----------- -----------
Total Proved........... 1,939,910 10,256,523 $63,988,512 $44,506,218
========= ========== =========== ===========
</TABLE>
Future revenue is prior to deducting state production taxes and ad valorem
taxes. Future net cash flow is after deducting these taxes, future capital costs
and operating expenses, but before consideration of federal income taxes. In
accordance with SEC guidelines, the future net cash flow has been discounted at
an annual rate of ten percent to determine its "present worth". The present
worth is shown to indicate the effort of time on the value of money and should
not be construed as being the fair market value of the properties.
The oil reserves include oil and condensate. Oil volumes are expressed in
barrels (42 U.S. gallons). Gas volumes are expressed in thousands of standard
cubic feet (Mcf) at contract temperature and pressure base.
Our estimates are for proved reserves only and do not include any probable
or possible reserves nor have any values been attributed to interests in acreage
beyond the location for which undeveloped reserves have been estimated.
Oil and gas prices being received at December 31, 1996 were utilized as
furnished. Direct lease operating expenses are based on historical data for 1995
and 1996 and do not include general and administrative
A-1
<PAGE> 87
overhead. Investments are capital costs for pumping unit installations,
work-overs and drilling costs and were utilized as furnished. All economic
factors were held constant in accordance with SEC guidelines.
An on-site field inspection of the properties has not been performed nor
have the mechanical operation or condition of the wells and their related
facilities been examined nor have the wells been tested by Cawley, Gillespie &
Associates, Inc. Possible environmental liability related to the properties has
not been investigated nor considered. The cost of plugging and the salvage value
of equipment at abandonment have not been included.
The reserve classifications and the economic considerations used herein
conform to the criteria of the Securities and Exchange Commission. The reserves
and economics are predicated on regulatory agency classifications, rules,
policies, laws, taxes and royalties currently in effect except as noted herein.
The possible effects of changes in legislation or other Federal or State
restrictive actions which could affect the reserves and economics have not been
considered.
The proved reserve estimates and economic forecasts were based upon
interpretations of data furnished by your office and available from our files.
All estimates represent our best judgment based on the data available at the
time of preparation. It should be realized that the reserve estimates, the
reserves actually recovered, the revenue derived therefrom and the actual costs
incurred could be more or less than the estimated amounts. Additionally, the
prices and costs may vary from those utilized which may increase or decrease
both the estimated proved reserve volumes and future net revenues therefrom.
Ownership interests in the oil and natural gas properties were accepted as
furnished by Brigham Oil & Gas, L.P., and has not been independently confirmed.
We are independent registered professional engineers and geologists. We do not
own an interest in the properties of Brigham Oil & Gas, L.P. and are not
employed on a contingent basis. Our workpapers and related data utilized in the
preparation of these estimates are available in our office.
Yours very truly,
Cawley, Gillespie & Associates, Inc.
/s/ AARON CAWLEY
-------------------------------------------
Aaron Cawley, P.E.
Executive Vice President
A-2
<PAGE> 88
======================================================
NO DEALER, SALESPERSON OR OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS OTHER THAN THOSE CONTAINED IN THIS
PROSPECTUS IN CONNECTION WITH THE OFFER MADE BY THIS PROSPECTUS AND, IF GIVEN OR
MADE, SUCH INFORMATION OR REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING BEEN
AUTHORIZED BY THE COMPANY OR ANY OF THE UNDERWRITERS. THIS PROSPECTUS DOES NOT
CONSTITUTE AN OFFER TO SELL OR THE SOLICITATION OF ANY OFFER TO BUY ANY
SECURITIES OTHER THAN THE SHARES OF COMMON STOCK OFFERED BY THIS PROSPECTUS, NOR
DOES IT CONSTITUTE AN OFFER TO SELL OR A SOLICITATION OF ANY OFFER TO BUY THE
SHARES OF COMMON STOCK BY ANYONE IN ANY JURISDICTION IN WHICH SUCH OFFER OR
SOLICITATION IS NOT AUTHORIZED, OR IN WHICH THE PERSON MAKING SUCH OFFER OR
SOLICITATION IS NOT QUALIFIED TO DO SO, OR TO ANY PERSON TO WHOM IT IS UNLAWFUL
TO MAKE SUCH OFFER OR SOLICITATION. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR
ANY SALE MADE HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY IMPLICATION
THAT THE INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO
THE DATE HEREOF.
------------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
-----
<S> <C>
Prospectus Summary....................... 3
Risk Factors............................. 10
The Company.............................. 16
Use of Proceeds.......................... 16
Dividend Policy.......................... 17
Dilution................................. 17
Capitalization........................... 19
Selected Financial Data.................. 20
Management's Discussion and Analysis of
Financial Condition and Results of
Operations............................. 22
Business and Properties.................. 28
Management............................... 43
Certain Transactions..................... 48
Principal Stockholders................... 50
Description of Capital Stock............. 52
Shares Eligible for Future Sale.......... 53
Underwriting............................. 55
Legal Matters............................ 56
Experts.................................. 57
Available Information.................... 57
Glossary of Certain Oil and Gas Terms.... 58
Index to Financial Statements............ F1-1
Letter of Cawley, Gillespie & Associates,
Inc.................................... A-1
</TABLE>
UNTIL JUNE 2, 1997 (25 DAYS AFTER THE DATE OF THIS PROSPECTUS), ALL DEALERS
EFFECTING TRANSACTIONS IN THE SHARES OF THE COMMON STOCK, WHETHER OR NOT
PARTICIPATING IN THIS DISTRIBUTION, MAY BE REQUIRED TO DELIVER A PROSPECTUS.
THIS IS IN ADDITION TO THE OBLIGATION OF DEALERS TO DELIVER A PROSPECTUS WHEN
ACTING AS UNDERWRITERS AND WITH RESPECT TO THEIR UNSOLD ALLOTMENTS OR
SUBSCRIPTIONS.
======================================================
======================================================
3,000,000 SHARES
[BRIGHAM EXPLORATION COMPANY LOGO]
COMMON STOCK
-------------------------
PROSPECTUS
-------------------------
BEAR, STEARNS & CO. INC.
HOWARD, WEIL,
LABOUISSE, FRIEDRICHS
INCORPORATED
RAUSCHER PIERCE REFSNES, INC.
MAY 8, 1997
======================================================
