##### Table of Contents



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
 FORM 10-K x
    
    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the fiscal year ended December 31, 2003
OR
 o
    
    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 Commission file number: 000-22433  Brigham Exploration Company  Delaware
(State or other jurisdiction of
incorporation or organization)
    
    75-2692967
(I.R.S. Employer Identification No.)
 6300 Bridge Point Parkway, Building 2, Suite 500, Austin, Texas 78730   (512) 427-3300
 Title of Each Class
    
    Name of Each Exchange on Which RegisteredNone
    
    None
 Securities registered pursuant to Section 12(g) of the Act:Common Stock, $.01 par value
(Title of Class) Indicate by check mark whether the Registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding twelve months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes x  No o Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of Registrants knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12 b-2 of the Act). Yes o  No x As of June 30, 2003, the registrant had 20,562,410 shares of voting common
outstanding. The aggregate market value of the registrants outstanding shares
of voting common stock held by non-affiliates, based on the closing price of
these shares on June 30, 2003 of $5.01 per share as reported on The Nasdaq
Stock MarketSM, was $50.5 million. Shares held by each executive officer and
director and by each person who owns 10% or more of the outstanding common
stock are considered affiliates. The determination of affiliate status is not
necessarily a conclusive determination for other purposes. As
of March 26, 2004, the registrant had 39,562,696 shares of voting common stock outstanding. DOCUMENTS INCORPORATED BY REFERENCE Portions of the definitive proxy statement for the Registrants 2004
Annual Meeting of Stockholders to be held on June 3, 2004, are incorporated by
reference in Part III of this Form 10-K. Such definitive proxy statement will
be filed with the Securities and Exchange Commission not later than 120 days
subsequent to December 31, 2003.




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TABLE OF CONTENTS PageITEM 1.
    
    BUSINESS
    
    
    1ITEM 2.
    
    PROPERTIES
    
    
    6ITEM 3.
    
    LEGAL PROCEEDINGS
    
    
    17ITEM 4.
    
    SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS
    
    
    17EXECUTIVE OFFICERS OF THE REGISTRANT
    
    
    18PART IIITEM 5.
    
    MARKET FOR REGISTRANTS COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
    
    
    19ITEM 6.
    
    SELECTED CONSOLIDATED FINANCIAL DATA
    
    
    22ITEM 7.
    
    MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
    
    
    24ITEM 7A.
    
    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
    
    
    50ITEM 8.
    
    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
    
    
    53ITEM 9.
    
    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
    
    
    53ITEM 9A.
    
    CONTROLS AND PROCEDURES
    
    
    53PART IIIITEM 10.
    
    DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
    
    
    54ITEM 11.
    
    EXECUTIVE COMPENSATION
    
    
    54ITEM 12.
    
    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
    
    
    54ITEM 13.
    
    CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
    
    
    54ITEM 14.
    
    PRINCIPAL ACCOUNTANT FEES AND SERVICES
    
    
    54PART IVITEM 15.
    
    EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
    
    
    55GLOSSARY OF OIL AND GAS TERMS
    
    
    56SIGNATURES
    
    
    58INDEX TO FINANCIAL STATEMENTS
    
    
    F-1Letter Agreement1997 Director Stock Option PlanFirst Amend.to Amended Subordinated Credit AgmtSubsidiaries of the RegistrantConsent of PricewaterhouseCoopers LLPCertification of CEO Pursuant to Section 302Certification of CFO Pursuant to Section 302Certification of CEO Pursuant to Section 906Certification of CFO Pursuant to Section 906
 i




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BRIGHAM EXPLORATION COMPANY 2003 ANNUAL REPORT ON FORM 10-K PART I 
 ITEM 1. BUSINESS Overview We are an independent exploration, development and production company that
utilizes 3-D seismic imaging and other advanced technologies to systematically
explore for and develop domestic onshore oil and natural gas reserves. We focus
our activities in provinces where we believe 3-D seismic technology can be used
effectively to maximize our return on invested capital by reducing drilling
risk and enhancing our ability to grow reserves and production volumes in a
cost-effective manner. Our exploration and development activities are
concentrated in three provinces: the onshore Texas Gulf Coast, the Anadarko
Basin and West Texas. Since our inception in 1990, we have evolved from a pioneering, 3-D
seismic-driven exploration company to a balanced exploration and development
company with technical and operational expertise and a strong production base.
We benefit from our focus in five proven and complementary onshore trends
contained within our three core provinces, which provides us with diversification in
our drilling investments. We believe that our five focus trends provide us with
a broad range of risk profiles and reserve potentials for both natural gas and
oil prospects and associated geographical and operational diversification. As a
result, we are not dependent on our continued drilling success in a single core
trend. Instead, in any given year our overall results may be positively
impacted by the results in one or several of our focus trends. We believe that
this diversification and our knowledge base in these trends, as demonstrated by
our track record, are significant distinguishing factors for us. We have generated a multi-year inventory of exploration prospects, which, due
to our field discoveries, are complemented by a multi-year inventory of
development locations. Since our inception through December 31, 2003, we have
drilled 592 wells, consisting of 453 exploratory and 139 development wells with
an aggregate completion rate of 69% and an average all-sources finding cost of
$1.41 per Mcfe. In 2003 we spent $46.8 million in net capital expenditures on
oil and gas activities and achieved an all-sources finding cost of $1.97 per
Mcfe. Additionally, we completed 33 out of 37 wells drilled in 2003 replacing
223% of our 2003 production. To further capitalize on our multi-year inventory
of exploration and development prospects, we currently plan to significantly
increase our oil and gas capital expenditures in 2004 to approximately $78.9
million,representing a 69% increase over 2003 oil and gas
capital expenditures. We have accumulated 3-D seismic data covering approximately 9,948 square miles
(6.4 million acres) in over 28 geologic trends in seven provinces and seven
states. We focus our 3-D seismic acquisition efforts in and around existing
producing fields where we can benefit from the imaging of producing analog
wells. These 3-D defined analogs, combined with our experience in drilling 592
wells in our 3-D project areas, provide us with a knowledge base to evaluate
other potential geologic trends, 3-D seismic projects within these trends and
prospective 3-D delineated drilling locations. Combining our geologic and geophysical expertise with a sophisticated land
effort, we manage the majority of our projects from conception through 3-D
acquisition, processing and interpretation and leasing. In addition, we manage
the negotiation and drafting of most of our geophysical exploration agreements,
resulting in reduced contract risk and more consistent deal terms. Because we
generate most of our projects, we can often control the size of the working
interest that we retain as well as the selection of the operator and the
non-operating participants. Consistent with our business strategy, we have
increased the working interest we retain in certain of our 2004 projects, based
upon our improved capital availability. For example, approximately 37% of our
budgeted 2004 drilling expenditures are allocated to the Vicksburg trend, where
we expect to retain an average working interest of 61% (relative to our
historical average working interest of 40% through 2003). Further,
approximately 25% of our budgeted 2004 drilling expenditures are allocated to
the Frio trend, where we expect to retain an average working interest of 55%
(relative to our historical average working interest of 47% through 2003). Business Strategy Our business strategy is to create stockholder value by growing reserves,
production volumes and cash flow through exploration and development drilling
in areas where we believe our operations will likely result in a high return on
our invested capital. Key elements of our business strategy include:  
    
    Focus on Core Provinces and Trends.We have accumulated and continue
to add to a multi-year inventory of 3-D seismic and geologic data and
have developed a strong technical knowledge base in the following
geologic trends within our core
provinces: the Vicksburg and Frio trends in the onshore Texas Gulf Coast,
the Springer and Hunton trends in the Anadarko Basin and the Horseshoe
Atoll trend of West Texas. 1




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Further, we believe our focus on these five
proven onshore trends within our three core provinces provides us with
important drilling investment diversification. Since 1999, our drilling
success in these trends has resulted in six significant field discoveries
and a multi-year inventory of development drilling locations. We plan to
focus a majority of our near term capital expenditures in these trends,
where we believe our accumulated data and knowledge base provide a
substantial competitive advantage.  
    
    Internally Generate Inventory of High Quality Exploratory Prospects.
We utilize 3-D seismic and other advanced technologies, including
computer-aided exploration, to generate and maintain a large multi-year
inventory of high quality exploratory prospects. Our highly skilled
staff of twelve geophysicists and geologists generates substantially all
of our prospects. We do not rely on third party generated opportunities,
which usually involve the payment of consideration over and above the
costs incurred to generate and drill the prospect. We believe that our
six field discoveries and our history of achieving low all-sources
finding costs over the last three, five and seven years, averaging
$1.50, $1.25 and $1.42 per Mcfe, respectively, reflect the quality and
depth of our 3-D delineated prospect inventory as well our ability to
continue to generate such opportunities.  
    
    Capitalize on Exploration Successes Through Development of Field
Discoveries. From 1990 to 1999, we grew our reserves and production
volumes primarily through successful 3-D delineated exploration
drilling. Due to our exploratory drilling success and the resulting
growth in our inventory of development drilling locations, approximately
60% of our drilling capital expenditures in 2001, 2002 and 2003 were
developmental. We believe our ability to balance our higher risk
exploratory drilling with lower risk development drilling has reduced
our risk profile. For 2004, we intend to allocate approximately 64% of
our total drilling expenditures for development drilling. See Item 2.
Properties and Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations2004 Outlook for
additional discussion about capital expenditures for 2004.  
    
    Accelerate Drilling of Our Prospect Inventory.To capitalize on our
multi-year inventory of exploration and development locations, our goal
is to substantially increase our drilling activity in 2004. In 2004 we
have budgeted $61.4 million in drilling capital expenditures,
representing a 75% increase over amounts spent in 2003. See Item 2.
Properties and Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations2004 Outlook for
additional discussion about capital expenditures for 2004.  
    
    Enhance Returns Through Operational Control.We seek to maintain
operational control of our exploration and drilling activities. As an
operator, we retain more control over the timing and selection of
drilling prospects, which enhances our ability to optimize our finding
and development costs and to maximize our return on invested capital.
Since we generate substantially all of our projects, we generally have
the ability to retain operational control over all phases of our
exploration and development activities. As of December 31, 2003, we
operated approximately 62% of the pre-tax PV-10% value of our proved
developed reserves. Further, in 2003 we operated 46% of the wells we
drilled, representing 70% of our drilling capital expenditures, and we
expect to operate the majority of the wells planned for 2004. Exploration and Development Staff Our experienced exploration staff includes six geophysicists, six geologists,
two computer applications specialists and two
geophysical/geological/engineering technicians. Our geologists and
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), provides us with valuable technical intellectual
resources. Our geophysicists and geologists have an average of more than 20
years of experience per person. We assembled our team according to the
expertise that these individuals have within producing basins where we focus
our exploration and development activities. By integrating both geologic and
geophysical expertise within our project teams, we believe we possess a
competitive advantage in our exploration approach. Our land department staff includes four landmen with an average of more than 21
years of experience primarily within our core provinces and three lease and
division order analysts. Our land department contributed to pioneering many of
the innovations that have facilitated exploration using large 3-D seismic
projects. Oil and Natural Gas Market and Major Customers Our natural gas produced in the onshore Texas Gulf Coast is sold to various
purchasers including intrastate pipeline purchasers, operators of processing
plants, and marketing companies under both monthly spot market contracts and
multi-year arrangements. The
vast majority of our natural gas sales are based on related natural gas index
pricing, and in some cases our gas is processed at a plant and we receive a
percentage of the value of natural gas liquids recovered. 2




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Our markets for natural gas produced in the Anadarko Basin are operators of
processing plants and marketing companies. We sell gas under both monthly spot
market contracts and multi-year contracts, which are normally based on related
natural gas index pricing. Some of our gas is processed and we receive a
percentage of the value of natural gas liquids recovered. Most of our natural gas in West Texas is sold to purchasers who process our
natural gas under multi-year contracts and pay us a percentage of the value
they receive from the resale of the natural gas liquids and the remaining
residue gas. We sell our crude oil and condensate at the lease to a variety of purchasers at
prevailing market prices under short-term contracts that normally provide for
us to receive an applicable posted price plus a market-based bonus. Since most of our oil and natural gas production is sold under price sensitive
or spot market contracts, the revenues generated by our operations are highly
dependent upon the prices of and demand for oil and natural gas. The price we
receive for our oil and natural gas production depends upon numerous factors
beyond our control, including seasonality, weather, competition, the condition
of the United States economy, foreign imports, political conditions in other
oil-producing and natural gas-producing countries, the actions of the
Organization of Petroleum Exporting Countries, and domestic government
regulation, legislation and policies. Decreases in the prices of oil and
natural gas could have an adverse effect on the carrying value of our proved
reserves and our revenues, profitability and cash flow. Although we are not
currently experiencing any significant involuntary curtailment of our oil or
natural gas production, market, economic and regulatory factors may in the
future materially affect our ability to sell our oil or natural gas production.
See Item 7. Managements Discussion and Analysis of Financial Condition and
Results of OperationsRisk FactorsOil And Natural Gas Prices Fluctuate Widely
And Low Prices Could Have A Material Adverse Impact On Our Business And
Financial Results By Limiting Our Liquidity And Flexibility To Accelerate Our
Drilling Program and Item 7. Managements Discussion and Analysis of
Financial Condition and Results of OperationsRisk FactorsThe Marketability Of
Our Natural Gas Production Depends On Facilities That We Typically Do Not Own
Or Control Which Could Result In A Curtailment Of Production And Revenues. For
the year ended December 31, 2001, sales to Lantern Petroleum Corporation and
Highland Energy Company represented approximately 60% of our oil revenue and
58% of our natural gas revenue. In 2002, in an effort to achieve better price
realizations from the sale of our oil and natural gas, we decided to bring our
commodities marketing activities in-house so that we could market and sell our
oil and natural gas to a broader universe of potential purchasers. As a
consequence, on March 1, 2002, we ended our oil purchase agreement with Lantern
Petroleum and on July 1, 2002, we ended a similar gas sales and purchase
arrangement with Highland Energy Company. Due to the availability of other
markets and pipeline connections, we do not believe that the loss of any single
oil or natural gas customer would have a material adverse effect on our results
of operations. Competition The oil and gas industry is highly competitive in all of its phases. We
encounter competition from other oil and gas companies in all areas of our
operations, including the acquisition of seismic and leasing options and oil
and natural gas leases on properties to exploration and development of those
properties. Our 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 our competitors are large, well
established companies with substantially larger operating staffs and greater
capital resources than we do. Such companies may be able to pay more for seismic
and lease options on oil and natural gas properties and exploratory prospects
and to define, evaluate, bid for and purchase a greater number of properties
and prospects than our financial or human resources permit. Our ability to
acquire additional properties and to discover reserves in the future will be
dependent upon our ability to evaluate and select suitable properties and to
consummate transactions in a highly competitive environment. See Item 7.
Managements Discussion and Analysis of Financial Condition and Results of
OperationsRisk FactorsWe Face Significant Competition And Many Of Our
Competitors Have Resources In Excess Of Our Available Resources and Item 7.
Managements Discussion and Analysis of Financial Condition and Results of
OperationsRisk FactorsWe Have Substantial Capital Requirements For Which We
May Not Be Able To Obtain Adequate Financing. 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 we drill will be productive or that we will recover
all or any portion of our investment. Drilling for oil and natural gas may
involve unprofitable efforts, not only from dry wells, but also from wells that
are productive, but do not produce sufficient net revenues to return a profit
after drilling, operating and other costs. The cost and timing of drilling,
completing and operating wells is often uncertain. Our drilling operations may
be curtailed, delayed or canceled as a result of numerous factors, many of
which are beyond our control, including title problems, weather conditions,
delays by project participants, compliance with
governmental requirements and shortages or delays in the delivery of equipment
and services. Our future drilling activities may not be successful and, if
unsuccessful, such failure may have a material adverse effect on our business,
financial condition or results of operations. See Item 7. Managements
Discussion and Analysis of Financial Condition and Results of OperationsRisk
Factors Exploratory Drilling Is A Speculative Activity That May Not Result In
Commercially Productive Reserves And May Require Expenditures In Excess Of
Budgeted Amounts. 3




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In addition, use of 3-D seismic technology requires greater
pre-drilling expenditures than traditional drilling strategies. Although we
believe that our use of 3-D seismic technology will increase the probability of
drilling success, some unsuccessful wells are likely, and there can be no
assurance that unsuccessful drilling efforts will not have a material adverse
effect on our business, financial condition or results of operations. Our operations are subject to hazards and risks inherent in drilling for and
producing and transporting oil and natural gas, such as fires, natural
disasters, explosions, encountering formations with abnormal pressures,
blowouts, cratering, pipeline ruptures and spills, any of which can result in
the loss of hydrocarbons, environmental pollution, personal injury claims and
other damage to our properties and those of others. We maintain insurance
against some but not all of the risks described above. In particular, the
insurance we maintain does not cover claims relating to failure of title to oil
and natural gas leases, trespass during 3-D survey acquisition or surface
damage attributable to seismic operations, business interruption or loss of
revenues due to well failure. Furthermore, in certain circumstances in which
insurance is available, we 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 our business, financial condition and results of operations. See
Item 7. Managements Discussion and Analysis of Financial Condition and
Results of OperationsRisk FactorsWe Are Subject To Various Operating And
Other Casualty Risks That Could Result In Liability Exposure Or The Loss Of
Production And Revenues and Item 7. Managements Discussion and Analysis of
Financial Condition and Results of OperationsRisk FactorsWe May Not Have
Enough Insurance To Cover All Of The Risks We Face, Which Could Result In
Significant Financial Exposure. Employees On March 26, 2004, we had 55 full-time employees and two part-time employees.
None of these employees are represented by any labor union and we believe
relations with them are good. Facilities Our principal executive offices are located in Austin, Texas, where we lease
approximately 34,330 square feet of office space at 6300 Bridge Point Parkway,
Building 2, Suite 500, Austin, Texas 78730. Governmental Regulation Our oil and natural gas exploration, production, transportation and marketing
activities are subject to extensive laws, rules and regulations promulgated by
federal and state legislatures and agencies, including the Federal Energy
Regulatory Commission (FERC), the Environmental Protection Agency, the Texas
Commission on Environmental Quality (TCEQ), the Texas Railroad Commission and
the Oklahoma Corporation Commission. Failure to comply with such laws, rules
and regulations can result in substantial penalties. The legislative and
regulatory burden on the oil and gas industry increases our cost of doing
business and affects our profitability. Although we do not own or operate any pipelines or facilities that are directly
regulated by FERC, its regulation of third party pipelines and facilities could
indirectly affect our ability to transport or market our production. Moreover,
FERC has in the past, and could in the future impose price controls on the sale
of natural gas. In addition, we believe we are in substantial compliance with
all applicable laws and regulations, however, we are unable to predict the
future cost or impact of complying with such laws and regulations because they
are frequently amended, interpreted and reinterpreted. The states of Texas and Oklahoma, and many other states, require permits for
drilling operations, drilling bonds and reports concerning operations and
impose other requirements relating to the exploration and production of oil and
natural gas. These states also have statutes or regulations addressing
conservation matters, including provisions for the unitization or pooling of
oil and natural gas properties, the establishment of maximum rates of
production from wells and the regulation of spacing, plugging and abandonment
of such wells. Environmental Matters Our operations and properties are, like the oil and gas industry in general,
subject to extensive and changing federal, state and local
laws and regulations relating to environmental protection, including the
generation, storage, handling, emission, transportation and discharge of
materials into the environment, and relating to safety and health. The recent
trend in environmental legislation and regulation generally is toward stricter
standards, and this trend will likely continue. These laws and regulations may
require the acquisition of a permit or other authorization before construction
or drilling commences and for certain other activities; limit or prohibit
seismic acquisition, construction, drilling and other activities on certain
lands lying within wilderness and other protected areas; and impose substantial
liabilities for pollution resulting from our operations. 4




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The permits required
for many of our 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, we are in substantial
compliance with current applicable environmental laws and regulations, and we
have 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 us, as well as the oil and gas industry in general. The Comprehensive
Environmental Response, Compensation and Liability Act (CERCLA) and comparable
state statutes impose strict and arguably joint and several liability on owners
and operators of certain sites and on persons who disposed of or arranged for
the disposal of hazardous substances found at such sites. It is not uncommon
for the neighboring landowners and other third parties to file claims for
personal injury and property damage allegedly caused by the hazardous
substances released into the environment. The Resource Conservation and
Recovery Act (RCRA) and comparable state statutes govern the disposal of solid
waste and hazardous waste and authorize imposition of substantial fines and
penalties for noncompliance. Although CERCLA currently excludes petroleum from
its definition of hazardous substance, state laws affecting our 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 us, to prepare and implement spill
prevention, control countermeasure and response plans relating to the possible
discharge of oil into surface waters. The Oil Pollution Act of 1990 (OPA)
contains numerous requirements relating to the prevention of and response to
oil spills into waters of the United States. For onshore and offshore
facilities that may affect waters of the United States, the OPA requires an
operator to demonstrate financial responsibility. Regulations are currently
being developed under federal and state laws concerning oil pollution
prevention and other matters that may impose additional regulatory burdens on
us. 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. The Clean Air Act of 1970 and its subsequent
amendments in 1990 and 1997 also impose permit requirements and necessitate
certain restrictions on point source emissions of volatile organic carbons
(nitrogen oxides and sulfur dioxide) and particulates with respect to certain
of our operations. We are required to maintain such permits or meet general
permit requirements. The Environmental Protection Agency (EPA) and designated
state agencies have in place regulations concerning discharges of storm water
runoff and stationary sources of air emissions. These programs require covered
facilities to obtain individual permits, participate in a group or seek
coverage under an EPA general permit. Most agencies recognize the unique
qualities of oil and gas exploration and production operations. Both the EPA
and TCEQ have adopted regulatory guidance in consideration of the operational
limitations on these types of facilities and their potential to emit air
pollutants. We believe that we 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 us. Operations and Operations Staff In an effort to retain better control of our project timing, drilling and
operational costs and production volumes, we have significantly increased the
percentage of the wells that we operate in the past several years. We operated
46% of the gross wells and 69% of the net wells that we drilled during 2003, as
compared with 10% of the gross wells and 17% of the net wells we drilled during
1996. As a result of our increased operational control in recent years, wells
operated by us constituted 62% of the pre-tax PV-10% value of our proved developed
reserves at year-end 2003, as compared to only 5% at year-end 1996. Our operations staff includes five engineers who have drilling, reservoir,
environmental and operations engineering experience primarily within our three
core provinces. These engineers work closely with our geologist and
geophysicist and are integrally involved in all phases of the exploration and
development process, including preparation of pre- and post-drill reserve
estimates, well design, production management and analysis of full cycle risked
drilling economics. We conduct field operations for our operated oil and
natural gas properties through our field production superintendent and third
party contract personnel. Website Access to Company Reports We make available free of charge through our website, www.bexp3d.com, our
annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on
form 8-K, and all amendments to those reports as soon as reasonably practicable
after such material is electronically filed with the Securities and Exchange
Commission. Information on our website is not a part of this report. 5




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ITEM 2. PROPERTIES Our exploration and development activities are focused primarily in the onshore
Texas Gulf Coast, the Anadarko Basin of northwest Oklahoma and the Texas
Panhandle, and West Texas. We focus our activity in provinces where we believe
3-D seismic technology can be effectively used to maximize our return on
capital invested by reducing drilling risk and enhancing our ability
to cost-effectively grow reserves and production volumes. For the three-year period ended December 31, 2003, we completed 81 gross wells
(30.4 net) in 93 attempts for a completion rate of 87% at an average
all-sources finding cost of $1.50 per Mcfe. We have budgeted approximately
$61.4 million to drill approximately 36 development wells and 23 exploratory
wells during 2004. See Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations 2004 Outlook. The following
is a summary of our properties by major province as of December 31, 2003,
unless otherwise noted:  Year EndedDecember 31, 2003
    
    At December 31, 2003Drilling
    
    AverageCapital
    
    Daily
    
    Proved
    
    Pre-tax
    
    %
    
    Productive
    
    3-D SeismicExpenditures
    
    Production
    
    Reserves
    
    PV-10% (a)
    
    Natural
    
    Wells
    
    DataProvince
    
    (Millions)
    
    (MMcfe/d)
    
    (Bcfe)
    
    (Millions)
    
    Gas
    
    Gross
    
    Net
    
    (Sq. Miles)Texas Gulf Coast
    
    $
    24.6
    
    
    18.3
    
    
    72.3
    
    $
    196.8
    
    
    82
    %
    
    
    62
    
    
    19.2
    
    
    3,456Anadarko Basin
    
    
    9.0
    
    
    6.7
    
    
    51.7
    
    
    122.3
    
    
    93
    %
    
    
    122
    
    
    28.5
    
    
    2,204West Texas/Other
    
    
    1.5
    
    
    4.7
    
    
    10.2
    
    
    24.7
    
    
    20
    %
    
    
    98
    
    
    26.9
    
    
    4,288Total
    
    $
    35.1
    
    
    29.7
    
    
    134.2
    
    $
    343.8
    
    
    82
    %
    
    
    282
    
    
    74.6
    
    
    9,948  
 (a)
    
    Standardized measure at December 31, 2003, was $261.6 million. Texas Gulf Coast The onshore Texas Gulf Coast region is a high potential, multi-pay province
that lends itself to 3-D seismic exploration due to its substantial structural
and stratigraphic complexity. In addition, certain sand reservoirs display
seismic bright spots, which can be direct hydrocarbon indicators and can
result in greatly reduced drilling risk. However, bright spots are not always
reliable as direct hydrocarbon indicators and do not generally assess reservoir
productivity. We believe our established 3-D seismic exploration approach,
combined with our exploration staffs extensive experience in the Texas Gulf
Coast and accumulated knowledge base in this province, particularly given our
recent drilling successes, provides us with significant competitive advantages.
The majority of our Texas Gulf Coast activity is currently concentrated in the
Vicksburg and Frio trends. Over the past three years we have spent approximately 68% of our total capital
expenditures for drilling, land and geological and geophysical in the onshore
Texas Gulf Coast region and have completed 37 gross wells (15.6 net) in 41
attempts for a completion rate of 90%. Production from the onshore Texas Gulf
Coast region represented 61% of our average daily production in 2003, up from
41% in 2001. During 2003, we completed 15 gross wells (8.2 net) in 17 attempts for a
completion rate of 88% in the onshore Texas Gulf Coast. We operated 12 of the
17 wells that we drilled. Eleven of the wells we drilled were exploratory and
six were developmental. Our development drilling was focused in the Providence,
Home Run and Floyd Fault Block Fields. In addition, we made a new Vicksburg
field discovery with the successful completion of our Floyd South Fault Block
Field discovery well. For 2004, we intend to focus our drilling activity in this province on the
development of our Home Run, Triple Crown, Floyd Fault Block and Floyd South
Field discoveries in the Vicksburg, the further development of our Providence
Field in the Frio and the continued drilling of our 3-D delineated exploration
inventory in the Vicksburg and Frio trends. We expect to spend approximately
$38.9 million to drill 25 wells in the onshore Texas Gulf Coast. Approximately
52% percent of these drilling capital expenditures are budgeted for development
drilling activities, with the remainder allocated towards exploration drilling. Vicksburg Trend Since 1999, our exploration efforts in the Vicksburg trend have been focused in
the general area of our Diablo Project located in the Brooks County area of
South Texas. At inception we owned a 34% working interest in the Diablo
Project, with another industry
participant owning the remaining 66%. Prior to November 2003, we had
approximately 8,000 acres of leasehold and 218 square miles of 3-D seismic data
in the area. 6




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In November 2003, we significantly expanded our ownership in this
area when we signed two new joint ventures with our same industry participant covering
an additional 5,150 acres, increasing our total acreage under control in the
area to approximately 13,150 acres. In the new joint ventures we have the
opportunity to retain larger working interests, ranging from 50% to 100%, while
also retaining all the associated drilling and completion operations. As of December 31, 2003, we had completed 18 wells in 18 attempts in the
Vicksburg trend and generated four significant discoveries at the Home Run
Field, the Triple Crown Field, the Floyd Fault Block Field and the Floyd South
Fault Block Field. The primary objectives within this area are large structural
features at depths ranging from 9,000 to 14,000 feet. We believe that we have a substantial multi-year inventory of proved
undeveloped and non-proved Vicksburg drilling locations in our Home Run, Triple
Crown, Floyd Fault Block and Floyd South Fault Block Fields, and other adjacent
fault blocks. In 2003 we invested approximately $10.9 million to drill and complete five
wells in the Vicksburg with an average working interest of 50%. For 2004 we
plan to devote approximately $22.8 million in drilling capital expenditures to
drill six development wells and two exploratory wells in the Vicksburg. We
expect to direct a significant portion of our future capital expenditures
towards both proved and non-proved drilling opportunities in this area. Floyd Fault Block. We drilled our Floyd Fault Block discovery well, the
Sullivan #8, in December 2002. We retained a 34% working and 25% revenue
interest in the Sullivan #8, which proved up reserves in one of several fault
blocks adjacent to our Home Run and Triple Crown Fields. The Sullivan #8
encountered approximately 172 feet of apparent net pay in several lower
Vicksburg pay intervals at depths between 12,900 and 13,650 feet. The quantity
of pay encountered is approximately three times that encountered in our typical
Home Run Field well. The Sullivan #8 began producing in March 2003 at a rate of approximately 9.2
MMcf of natural gas and 580 barrels of condensate per day (12.7 MMcfe/d) or
approximately 3.2 MMcfe/d net to our 25% revenue interest. After producing
approximately 2.9 Bcfe, in October 2003 the well stopped producing due to an
apparent blockage above the producing formation. Prior to the blockage, the
Sullivan #8 was producing 7.7 MMcf of natural gas and 400 barrels of condensate
per day (10.1 MMcfe/d). In February 2004, the operator of the well
reestablished production at approximately 2.5 MMcf of natural gas and 100
barrels of condensate per day (3.1 MMcfe/d). It is uncertain how long the
Sullivan #8 will continue to produce in its current state. If the well stops
producing in the future, it is highly likely that the well will be sidetracked
or redrilled. We retained a 34% working interest and 25% net revenue interest in the Sullivan
#9 and the Sullivan #10, the first two development wells in our Floyd Fault
Block Field. The most recent well, the Sullivan #10, encountered approximately
187 feet of apparent net pay, and was completed and fracture stimulated. The
Sullivan #10 commenced production at an initial rate of approximately 11.9 MMcf
of natural gas and 689 barrels of condensate per day (16.0 MMcfe/d) or
approximately 3.9 MMcfe/d net to our revenue interest, with a flowing tubing
pressure of approximately 8250 psi. We estimate that up to seven additional
wells will be required for full development of the Floyd Fault Block Field,
four of which were classified as proved undeveloped locations at December 31,
2003. We expect to drill two additional wells within the Floyd Fault Block
Field in 2004. Home Run Field &
Triple Crown Field. We discovered the Home Run Field in late
1999 and the Triple Crown Field in 2001. As of December 31, 2003, we had
drilled and completed 14 consecutive wells in these fields with an average
working interest of 42%. During 2003, we drilled and completed two wells in the
Home Run Field and expect to drill up to three wells within the Home Run Field
and one well within the Triple Crown Field in 2004. We believe that the Home
Run and Triple Crown Fields could require up to 45 additional wells for full
development, eleven of which were classified as proved undeveloped at December 31,
2003. Floyd South Fault Block
Field. We drilled our Floyd South Fault Block Field
discovery well, the D.J. Sullivan F#1, in December 2003. The Sullivan F #1,
which was drilled to a total depth of 14,177 feet, was the first well to test
the Floyd South fault block as part of the new Vicksburg joint venture entered
into in 2003 with our industry participant. The Sullivan F#1 encountered
approximately 55 feet of apparent net pay in the Lower Vicksburg and commenced
production to sales in January 2003 at a rate of approximately 6.7 MMcf of
natural gas and 293 barrels of condensate per day (8.5 MMcfe/d) with a flowing
tubing pressure of 8100 psi, or approximately 3.3 MMcfe/d net to our 39%
revenue interest. We operated the drilling of the Sullivan F #1, retaining a
working interest of 100% before and 50% after casing point. We currently plan
to commence drilling the first development well in the Floyd South Fault Block
Field during the second quarter of 2004. We will retain a 50% working interest
before and after casing point in the first development well and any other wells
subsequently drilled in the Floyd South Fault Block Field. We believe that the
Floyd South Fault Block Field could require three to six wells for full
development, three of which were classified as proved undeveloped at December
31, 2003. Adjacent Fault Blocks to
Prior Field Discoveries. In early 2004, the Sullivan
E #1 was drilled to a total depth of 14,650 feet to test the Diablo East fault
block as part of our new Vicksburg joint ventures. Despite encountering over
400 gross feet of what was apparently
gas bearing sands, it was determined that the prospective zones were tight and
the well was plugged and abandoned. We are evaluating the results of this well
to determine if another test of the Diablo East fault block is merited. Prior
to drilling the Sullivan E #1, we had completed eighteen consecutive Vicksburg
wells in four different fault blocks. 7




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We have additional unproven fault blocks
to test, most of which are adjacent to our prior discoveries. Additional Vicksburg
Potential. We continue to generate prospects in the
Vicksburg trend, and seek to continue to expand our operations in this core
trend, which is currently the single most important of the five focus trends. Frio Trend In the Frio trend of the Upper Texas Gulf Coast, we have accumulated an
inventory of over 1,880 square miles (1.2 million acres) of predominantly
non-proprietary 3-D seismic data located primarily in Brazoria, Calhoun,
Matagorda, and Jackson Counties in the Upper Texas Gulf Coast. Within this
trend we are targeting both the shallow non-pressured and the deeper pressured
Frio sands. Reservoirs in this trend can display seismic bright spots, which
can be direct hydrocarbon indicators and can result in greatly reduced drilling
risk. However, bright spots are not always reliable as direct hydrocarbon
indicators and do not generally assess reservoir productivity. Since late 2000, we have completed 19 wells in 21 attempts in the Frio trend
and discovered our prolific Providence Field. In 2003 we invested approximately
$13 million in the Frio trend to drill 11 wells, 10 of which were completed.
Our average working interest in these wells was 61%. For 2004 we estimate that
our drilling expenditures will be approximately $15.6 million to drill five
development wells with an average working interest of 52% and eleven
exploratory wells with an average working interest of 57%. Providence Frio Field. We discovered the Providence Field during the fourth
quarter of 2001, when we drilled and completed the Staubach #1. Including the
Staubach #1 discovery well in 2001, we have now completed five wells in five
attempts in the Providence Field with an average working interest of 40%.
During 2002 and 2003 we invested approximately $7.5 million in the drilling of
our Providence Field, which generated approximately $24 million in net revenue
during this time period. During 2004 we expect to drill one to two additional
wells in the Providence Field. General Patton Project. In early 2003, we acquired 84 square miles of new
proprietary seismic data along the same trend that has provided most of our
recent Frio discoveries, including the Providence Field. We sold a 50% working
interest in the project to participants on a promoted basis. As a result, we
paid 33.3% of the seismic and pre-seismic land costs for our 50% working
interest in the project, while also retaining operational control. We began
interpreting the data in May 2003 and commenced our drilling program in this
project in August 2003 with the drilling of the Harriman #1 discovery. We
operated and retained a 50% working and 39% revenue interest in the Harriman
#1, which commenced production in early October 2003 at an initial rate of
approximately 4.9 MMcf of natural gas and 50 barrels of oil per day (5.2
MMcfe/d). In October 2003, we commenced drilling our second General Patton Project well,
the Harrison #1, to test our Corner Pocket Prospect. In February 2004, the
Harrison #1 commenced production at an initial rate of approximately 2.2 MMcf
of natural gas and 113 barrels of oil per day (2.9 MMcfe/d). We retained a 50%
working interest in the Harrison #1, which may set up one to two offsets that
will be drilled during 2004. To date, we have completed two wells in two
attempts in our General Patton Project, and currently expect to drill
approximately eight General Patton Frio wells during 2004. Bayou Bengal Project. In late 2003 and early 2004 we acquired approximately 77
square miles of existing non-proprietary and 54 square miles of new proprietary
3-D seismic data in our Bayou Bengal Project. This project is located along
the same trend that has provided most of our recent Frio discoveries. We sold
a 25% working interest in the project to a participant on a promoted basis. As
a result, we paid 60% of the seismic and pre-seismic land costs for our 75%
interest in the project, while also retaining operational control. We
commenced drilling our first well in this project, the Trull B #2, during
October 2003. The Trull B #2, which targeted a total depth of 9,500 feet, was
completed to sales in January 2004 at an initial rate of approximately 2.3 MMcf
of natural gas and 34 barrels of oil per day (2.5 MMcfe/d). This production
rate was constrained due to limited pipeline capacity. We retained a 75%
working and 56% revenue interest in this shallow Frio discovery. In December 2003, we drilled the Sartwelle #1, our second discovery in our
Bayou Bengal Project. The Sartwelle #1 commenced production to sales in
February 2004 at an initial rate of approximately 4.0 MMcf of natural gas and
42 barrels of oil per day (4.2 MMcfe/d) with a flowing tubing pressure of 4750
psi. We retained a 63% working and 47% revenue interest in the Sartwelle #1,
which was drilled to a total depth of approximately 10,450 feet. To date, we
have completed two wells in two attempts in our Bayou Bengal Project, and
currently expect to drill two additional wells during 2004. Other Frio. In February 2004 we completed the Randall #1 in the Lower Frio at
an initial rate of approximately 2.0 MMcf of natural gas and 12 barrels of oil
per day (2.1 MMcfe/d) with a flowing tubing pressure of 6700 psi. We operated
the Randall #1 with a 94%
working and 70% revenue interest, which was drilled to a total depth of
approximately 14,200 feet. We believe that the Randall #1 could set up one
additional offset, which we expect to commence later in 2004. 8




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In addition to our ongoing drilling program in the Frio trend, we continue to
generate additional drilling inventory from our 3-D seismic database of more
than 1,880 square miles in this trend. Historically, approximately 20% of our
exploration wells targeted higher risk, higher reserve potential objectives.
The Staubach #1 discovery well for our Providence Field is an example of a
successful higher potential Frio test. However, as in recent years, the vast
majority of our Frio exploration wells are expected to test relatively lower
risk, primarily amplitude defined prospects. In recent years these prospects
have provided us with a high success rate and a high rate of return on our
drilling capital investments. We also continue to add to our drilling inventory in the Frio by assembling
several new proprietary 3-D seismic projects in the same trend where we have
experienced significant drilling success in recent years. We expect to
commence acquisition of at least one additional proprietary 3-D project in the
third quarter of 2004. Other Texas Gulf Coast The Dinn Ranch Field. The Dinn Ranch Field is a Wilcox discovery located in
Duval County, Texas. We own interests in two wells within the field. The
first well, the Lopez #1, experienced operational difficulties, but was
eventually completed as a marginal producer. The second well, the Lopez #3, was
producing in February 2003 at a rate of approximately 16.5 MMcf of natural gas
per day. The Lopez #3 had produced approximately 2.9 Bcfe through December 31,
2003, and was producing approximately 6.3 MMcf of natural gas per day at
year-end. We retain 2% overriding royalty interests in these two wells that
convert to working interests at different payouts. In each of these two wells,
we will own a 12.5% working interest at 100% payout, which will increase to a
25% working interest at 200% payout. Payout occurs at the point in time when
the net proceeds from the sale of production from the well equals all of the
costs and expenses associated with the drilling and operation of the well. We
expect a third well to spud late in 2004, in which we plan to retain a 25%
ground floor working interest. Anadarko Basin The Anadarko Basin is located in northwest Oklahoma and the Texas Panhandle. We
believe this prolific natural gas producing province offers a combination of
lower risk exploration and development opportunities in shallower horizons, as
well as higher reserve potential in the deeper sections that have been
relatively under explored. We believe our drilling programs in the Anadarko Basin and West Texas generally
provide us with longer life reserves and help to balance our drilling program
in the prolific, but generally shorter reserve life, onshore Texas Gulf Coast
province. The stratigraphic and structural objectives in the Anadarko Basin can provide
excellent targets for 3-D seismic imaging. In addition, drilling economics in
the Anadarko Basin are enhanced by the multi-pay nature of many of these
prospects; with secondary or tertiary targets serving as either incremental
value or as alternatives in the event the primary target zone is not
productive. Our recent activity has been focused primarily in the Springer
Channel and Hunton trends. However, given the recent success of development
wells in a Springer Bar Field, discovered by us in late 2000, developmental
activity in this field accelerated during 2003. Over the past three years we have spent approximately 25% of our total capital
expenditures for drilling, land and geological and geophysical in the Anadarko
Basin and have completed 30 gross wells (9.6 net) in 35 attempts for a
completion rate of 86%. Production from the Anadarko Basin represented 23%
of our average daily production in 2003, down from 38% in 2001. During 2003, we completed 14 gross wells (4.8 net) in 15 attempts for a
completion rate of 93%. We operated four of the wells that we drilled in the
Anadarko Basin in 2003. Seven of the wells we drilled were exploratory and
eight were developmental. For 2004, we intend to continue to focus our drilling activity in this province
on our 3-D delineated exploration and development inventory in the Springer and
Hunton trends. We expect to spend approximately $20.8 million to drill 29
wells. Approximately 90% of these drilling capital expenditures are budgeted
for development drilling activities, with the remainder allocated towards
exploration drilling. Grady County Springer Bar Field In Grady County, Oklahoma we have approximately 105 square miles (67,200 acres)
of 3-D seismic data and together with our participants control over 10,000
leasehold acres in one of the most prolific producing areas of the Anadarko
Basin. In 2000, based on
our seismic interpretation of this data, we discovered a large,
stratigraphically defined Springer Bar field with the successful completion of
the Nix #1 in the Britt interval of the Springer formation. In late 2000, we
confirmed the field with the Pitchford #1 well, which produced from the same
Britt interval at a depth of approximately 14,550 feet. We own a 17.35% working
interest in the Nix #1 and a 32.27% working interest in the Pitchford #1. 9




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During 2003, we invested approximately $2.6 million in this area and completed
6 gross wells (1.1 net) in 7 attempts. Successful wells drilled in the field
have produced at initial rates generally ranging from 2 to 8 MMcfe per day,
with low production decline rates relative to our onshore Texas Gulf Coast
wells. Given our drilling success to date in the field, we are currently
budgeting to spend $4.3 million to drill twelve development wells with an
average working interest of 10% in this area in 2004. In early 2003 we participated in the successful drilling of the McCasland Farms
#2, which commenced production in May at an initial rate of approximately 4.5
MMcf of natural gas and 50 barrels of oil per day (4.8 MMcfe/d), or
approximately 0.9 MMcfe/d net to our 18.6% revenue interest. We also
participated with a 15% working interest in the Stonehocker #1, which began
producing to sales in July 2003 at a rate of approximately 7.0 MMcf of natural
gas per day, or approximately 0.8 MMcfe/d net to our 12% revenue interest. The Jones #2 commenced drilling in June 2003, and was subsequently completed to
sales in October 2003 at a rate of approximately 7.0 MMcf of natural gas and
100 barrels of oil per day (7.6 MMcfe/d), or 1.2 MMcfe/d net to our 15.9%
revenue interest. During September 2003, we participated in the Teel #1 with a
16% working interest, which commenced producing to sales in December 2003 at a
rate of approximately 6.9 MMcf of natural gas and 30 barrels of oil per day
(7.1 MMcfe/d), or 0.9 MMcfe/d net to our 13% revenue interest. In November
2003, we participated in the drilling of the Mack Farms #1 with a 14.6% working
interest. In February 2004, the Mack Farms #1 was being completed to sales
after encountering approximately 55 feet of apparent net pay in various
Springer intervals. Other Grady County Activity In April 2003, we participated in the Palmer #1 with a 29% working interest.
The Palmer #1 was completed and fracture stimulated in the Bromide formation
and initially produced at a rate of approximately 130 barrels of oil and 350
Mcf of natural gas per day (1.1 MMcfe/d) or 0.2 MMcfe/d net to our 22% revenue
interest. In November 2003, we participated with a 33% working interest in the
Cooper #1, which was drilled to a depth of approximately 16,374 feet and
encountered approximately 65 feet of apparent net pay in the Bromide formation.
The Cooper #1 was being completed in February 2004, with production to sales
expected in March 2004. We are also participating with a 29% working interest
in the Burton #1, another Bromide test that commenced drilling in March 2004.
Results for the Burton #1 are expected in late May 2004. Springer Channel Trend Our 3-D seismic inventory in the Springer Channel trend consists of over 629
square miles (402,560 acres) of 3-D seismic data covering portions of Dewey,
Blaine, Canadian, Grady and Caddo Counties, Oklahoma. Our activities in this
area target buried fluvial sand channels at depths of 9,000 to 12,000 feet, as
well as other secondary objectives. Since 2000, we have completed 11 wells in
15 attempts in the Springer Channel trend. In 2003 we invested approximately
$1.1 million in this trend to drill and complete five wells in 2003 with an
average working interest of 47%. During 2003 we participated in an 8,800 feet Springer test, the Bryson #1, with
a 36% working interest. The Bryson #1 was completed in the Springer interval
in July 2003 at a rate of approximately 2.5 MMcf of natural gas and 110 barrels
of oil per day (3.1 MMcfe/d), or approximately 0.9 MMcfe/d net to our 29%
revenue interest. We have budgeted approximately $4.2 million to drill four
development wells with an average working interest of 53% and six exploratory
wells with an average working interest of 21% in this trend in 2004. Hunton Trend Our 3-D seismic inventory in the Hunton trend consists of approximately 762
square miles (487,680 acres) of 3-D seismic data covering portions of Wheeler,
Hemphill and Roberts Counties, Texas and Beckham County, Oklahoma. The primary
exploration targets within this area are high potential, multi-well structural
features at depths ranging from 7,500 to 25,000 feet. The trend has
historically provided longer life reserves relative to our typical onshore
Texas Gulf Coast wells. For 2004, we have budgeted approximately $9.2 million
to drill three development wells in the Hunton trend with an average working
interest of 64%. Mills Ranch Field. In July 2000, we spud the Mills Ranch #1, which was drilled
directionally to a total depth of over 25,000 feet. We operated this well with
a 64% working interest. The Mills Ranch #1 paid out its drilling and completion
costs during its first year of production, and at year-end 2003 had produced
4.1 Bcfe and was producing approximately 1.3 MMcfe/d. In the third quarter
2002, we
began drilling the first offset to this discovery, the Mills Ranch #2. We
retained a 64% working interest in the Mills Ranch #2 well, which encountered
the basal Hunton porosity zone approximately 400 feet high to the comparable
zone in the discovery well. After running production casing to a depth of
approximately 23,900 feet and perforating and stimulating the lower Hunton
intervals, the well began producing at an initial rate of approximately 6.7
MMcf of natural gas per day with associated condensate. The upper intervals
were then stimulated and commingled into the producing stream, and the well was
put on production at an initial rate of approximately 2.0 MMcfe/d. 10




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We believe that the Mills Ranch Field could require up to seven additional
wells for full development, three of which were classified as proved
undeveloped at December 31, 2003. Drilling operations commenced in February
2004 on one of the proved undeveloped locations, the Mills Ranch #1-99S. The
Mills Ranch #1-99S is a reentry and sidetrack of a well previously drilled by
another operator. We expect to retain at least a 68% working interest in the
well, which is located several miles to the east of the Mills Ranch #1 and #2
wells. Currently there are three producing wells on the large structure,
including our Mills Ranch #1 and #2 on the west side. The three producing
wells on this structure have produced over 21 Bcfe to date. Subsequent to
drilling the Mills Ranch #1-99S, we plan to utilize the same large drilling rig
to drill two additional deep Hunton and Arbuckle wells during 2004. At least
one of these wells will be a development well on the west side of the field. Other Hunton Trend. We continue generating additional high potential
opportunities within the Hunton trend, including prospects with substantial
reserve potential in the stratigraphically deeper Arbuckle formation. The
Arbuckle is a several thousand-foot carbonate interval that has been productive
in a number of fields with significant cumulative production in the area.
However, the presence of a large carbonate Arbuckle interval does not insure
the presence of hydrocarbons, which in most cases will be dependent upon the
presence of a fault, change in stratigraphy or other hydrocarbon trapping
mechanism. The drilling depths for the Arbuckle vary widely within the trend,
from as shallow as 10,000 feet to depths as great as 25,000 feet. West Texas West Texas is predominantly an oil producing province with generally longer
lived reserves than that of the onshore Texas Gulf Coast. Our drilling activity
in our West Texas province has been focused primarily in various carbonate
reservoirs, including the Canyon Reef and Fusselman formations of the Horseshoe
Atoll trend, the Canyon Reef of the Eastern Shelf, and the Mississippian Reef
of the Hardeman Basin, at depths ranging from 7,000 to 13,000 feet. Over the past three years, we have spent approximately 7% of our total capital
expenditures for drilling, land and geological and geophysical in West Texas
and have completed 14 gross wells (5.2 net) in 17 attempts for a completion
rate of 82%. Production from West Texas represented 16% of our average daily
production in 2003 down from 21% in 2001. During 2003 we completed four gross wells (1.3 net) in five attempts for a
completion rate of 80%. We operated one of the five wells that we drilled in
West Texas in 2003. Four of the wells we drilled were exploratory and one was
developmental. For 2004, we intend to continue to focus our drilling activities on our 3-D
delineated exploration inventory in the Canyon Reef and Fusselman formations of
the Horseshoe Atoll trend. For 2004, we expect to spend approximately $1.7
million to drill one development well with a working interest of 40% and four
exploratory wells with an average working interest of 51%. Horseshoe Atoll Trend We have an inventory of approximately 1,049 square miles (671,360 acres) of 3-D
seismic data primarily covering significant portions of Scurry, Howard, Dawson
and Borden Counties in the Horseshoe Atoll trend, where we have accumulated
substantial experience exploring with 3-D seismic over the last twelve years.
In 2002, and in prior years, we frequently sold working interests in our West
Texas drilling prospects to industry participants on a promoted basis, which
has reduced our drilling risk while also contributing to lower finding costs
and higher rates of return. Since 2000, we have completed 12 gross wells in 12
attempts in the trend with an average working interest of 44%. 3-D Seismic Exploration We have accumulated 3-D seismic data covering approximately 9,948 square miles
(6.4 million acres) in over 28 geologic trends in seven basins and seven states.
We typically acquire 3-D seismic data in and around existing producing fields
where we can benefit from the imaging of producing analog wells. These 3-D
defined analogs, combined with our experience in drilling 592 wells in our 3-D
project areas, provide us with a knowledge base to evaluate other potential
geologic trends, 3-D seismic projects within these trends and prospective 3-D
delineated drilling locations. Through our experience in the early and mid
1990s, we developed an expertise in
the selection of geologic trends that we believe are best suited for 3-D
seismic exploration. In 1997 and 1998 we invested approximately $64 million in
3-D seismic and land in plays that we believed were providing optimal 3-D
delineated drilling economics. We have used the experience that we have gained
within our core trends to enhance the quality of subsequent projects in the
same trend and other analogous trends, to lower finding and development costs,
to compress project cycle times and to enhance our return on capital. 11




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Over the last twelve years we have accumulated substantial experience exploring
with 3-D seismic in a wide range of reservoir types and geologic trapping
mechanisms. In addition, we typically acquire digital data bases for
integration on our computer-aided exploration workstations, including digital
land grids, well information, log curves, production information, geologic
studies, geologic top data bases and existing 2-D seismic data. We use our
knowledge base, local geological expertise and digital data bases integrated
with 3-D seismic data to create maps of producing and potentially productive
reservoirs. As such, we believe our 3-D generated maps are more accurate than
previous reservoir maps (which generally are based on subsurface geological
information and 2-D seismic surveys), enabling us to more precisely evaluate
recoverable reserves and the economic feasibility of projects and drilling
locations. We have acquired most of our raw 3-D seismic data using seismic acquisition
vendors on either a proprietary basis or through alliances affording the
alliance members the exclusive right to interpret and use data for extended
periods of time. In addition, we have participated in non-proprietary group
shoots of 3-D seismic data (commonly referred to as spec data) when we
believe the expected full cycle project economics were justified, and we have
exchanged certain interests in some of our non-core proprietary seismic data to
gain access to additional 3-D seismic data. In most of our proprietary 3-D data
acquisitions and alliances, we have selected the sites of projects, primarily
guided by our knowledge and experience in the core provinces we explore,
established and monitored the seismic parameters of each project for which data
was shot, and typically selected the equipment that was used. Combining our geologic and geophysical expertise with a sophisticated land
effort, we manage the majority of our projects from conception through 3-D
acquisition, processing and interpretation and leasing. In addition, we manage
the negotiation and drafting of most of our geophysical exploration agreements,
resulting in reduced contract risk and more consistent deal terms. Because we
generate most of our projects, we can often control the size of the working
interest that we retain as well as the selection of the operator and the
non-operating participants. Consistent with our business strategy, we have
increased the working interest we retain in our projects, based upon capital
availability and perceived risk. Our average working interest in our 3-D
seismic projects acquired during 1996, 1997 and 1998 was 37%, 67% and 80%,
respectively. The 3-D seismic we acquired during 1999, 2000, 2001 and 2002 was
primarily through the exchange of certain rights in some of our non-core 3-D
seismic projects. Most of these exchanges did not include an industry
participant, therefore we retained potentially all interest in any prospects
generated from the newly acquired 3-D seismic data. In early 2003, we acquired
approximately 84 square miles of new proprietary 3-D seismic data in our
General Patton Project located in the Frio trend of the Upper Texas Gulf Coast.
We sold a working interest in this project to an industry participant on a
promoted basis and thus retained a 50% working interest in the project. In 2003
and early 2004, we acquired approximately 77 square miles of non-proprietary
and 54 square miles of new proprietary 3-D seismic data in our Bayou Bengal
Project, also located in the Frio trend of the Upper Texas Gulf Coast. We sold
a working interest in Bayou Bengal to an industry participant on a promoted
basis and retained a 75% working interest in the project. In 2004, we expect
to acquire approximately 267 square miles of new proprietary 3-D seismic data
within our core areas. Title to Properties We believe we have satisfactory title, in all material respects, to
substantially all of our producing properties in accordance with standards
generally accepted in the oil and gas industry. Our properties are subject to
royalty interests, standard liens incident to operating agreements, liens for
current taxes and other burdens, which we believe do not materially interfere
with the use of or affect the value of such properties. Our senior credit
facility and senior subordinated notes are secured by first and second liens,
respectively, against substantially all of our proved oil and natural gas
properties. See Item 7. Managements Discussion and Analysis of Financial
Condition and Results of OperationsLiquidity and Capital ResourcesSenior
Credit Facility and Item 7. Managements Discussion and Analysis of Financial
Condition and Results of OperationsLiquidity and Capital ResourcesSenior
Subordinated Notes. 12




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##### Table of Contents



Oil and Natural Gas Reserves Our estimated total net proved reserves of oil and natural gas as of December
31, 2003, 2002 and 2001 and the present values attributable to these reserves
as of those dates were as follows: At December 31,2003
    
    
    2002
    
    
    2001Estimated Net Proved Reserves:Natural gas (MMcf)
    
    
    109,403
    
    
    
    99,428
    
    
    
    88,594Oil (MBbls)
    
    
    4,130
    
    
    
    3,607
    
    
    
    3,748Natural gas equivalent (MMcfe)
    
    
    134,182
    
    
    
    121,070
    
    
    
    111,081Proved developed reserves as a percentage of net proved reserves
    
    
    50
    %
    
    
    46
    %
    
    
    49
    %Pre-tax PV-10% (in thousands)
    
    $
    343,813
    
    
    $
    307,374
    
    
    $
    146,807Standardized measure (in thousands)
    
    $
    261,598
    
    
    $
    239,698
    
    
    $
    120,924Base price used to calculate reserves (a):Natural gas (per MMbtu)
    
    $
    5.83
    
    
    $
    4.74
    
    
    $
    2.57Oil (per Bbl)
    
    $
    32.55
    
    
    $
    31.25
    
    
    $
    19.84
   (a)
    
    These base prices were adjusted to reflect applicable transportation and
quality differentials on a well-by-well basis to arrive at realized sales
prices used to estimate our reserves at these dates. The reserve estimates reflected above were prepared by Cawley, Gillespie &
Associates, Inc., our independent petroleum consultants, and are part of
reports on our oil and natural gas properties prepared by Cawley, Gillespie. In accordance with applicable requirements of the Securities and Exchange
Commission, estimates of our net 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 net proved reserves and future net revenues there from
are affected by oil and natural gas prices, which have fluctuated widely in
recent years. There are numerous uncertainties inherent in estimating oil and
natural gas reserves and their estimated values, including many factors beyond
our control. The reserve data set forth in the Cawley, Gillespie report
represents only estimates. Reservoir engineering is a subjective process of
estimating underground accumulations of oil and natural gas that cannot be
measured in an exact manner. The accuracy of any reserve estimate is a function
of the quality of available data and of engineering and geologic interpretation
and judgment. As a result, estimates of different engineers, including those
used by us, may vary. In addition, estimates of reserves are subject to
revision based upon actual production, results of future development and
exploration activities, prevailing oil and natural gas prices, operating costs
and other factors. The revisions may be material. Accordingly, reserve
estimates are often different from the quantities of oil and natural gas that
are ultimately recovered and are highly dependent upon the accuracy of the
assumptions upon which they are based. Our estimated net proved reserves have
not been filed with or included in reports to any federal agency. See Item 7.
Managements Discussion and Analysis of Financial Condition and Results of
OperationsRisk FactorsWe Are Subject To Uncertainties In Reserve Estimates
And Future Net Cash Flows. Estimates with respect to net proved reserves that may be developed and
produced in the future are often based upon volumetric calculations and upon
analogy to similar types of reserves rather than actual production history.
Estimates based on these methods are generally less reliable than those based
on actual production history. Subsequent evaluation of the same reserves based
upon production history will result in variations in the estimated reserves
that may be substantial. 13




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##### Table of Contents



Drilling Activities We drilled, or participated in the drilling of, the following number of wells
during the periods indicated: Year Ended December 31,2003(a)
    
    
    2002(b)
    
    
    2001(c)Gross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    NetExploratory wells:Natural gas
    
    
    12
    
    
    
    6.3
    
    
    
    4
    
    
    
    0.9
    
    
    
    5
    
    
    
    1.6Oil
    
    
    4
    
    
    
    1.3
    
    
    
    6
    
    
    
    0.9
    
    
    
    4
    
    
    
    2.6Non-productive
    
    
    5
    
    
    
    1.8
    
    
    
    1
    
    
    
    0.7
    
    
    
    6
    
    
    
    1.3Total
    
    
    21
    
    
    
    9.4
    
    
    
    11
    
    
    
    2.5
    
    
    
    15
    
    
    
    5.5Development wells:Natural gas
    
    
    11
    
    
    
    3.9
    
    
    
    7
    
    
    
    2.4
    
    
    
    15
    
    
    
    4.6Oil
    
    
    1
    
    
    
    0.4
    
    
    
    4
    
    
    
    1.7
    
    
    
    2
    
    
    
    1.1Non-productive
    
    
    3
    
    
    
    1.8
    
    
    
    1
    
    
    
    0.3
    
    
    
    0
    
    
    
    0.0Total
    
    
    15
    
    
    
    6.1
    
    
    
    12
    
    
    
    4.4
    
    
    
    17
    
    
    
    5.7
    (a)
    
    Excludes one (0.5 net) exploration well that is under evaluation and
temporarily abandoned.(b)
    
    Excludes one (0.2 net) development well that is productive but was
temporarily abandoned. There are no current plans to put this well on
production.(c)
    
    Excludes one (0.3 net) development well that was temporarily abandoned
during drilling due to operational difficulties encountered prior to
reaching total depth. We re-entered and completed this temporarily
abandoned well during 2002. We do not own drilling rigs and the majority of our drilling activities have
been conducted by independent contractors or by industry participant operators
under standard drilling contracts. Productive Wells and Acreage Productive Wells The following table sets forth our ownership interest at December 31, 2003 in
productive oil and natural gas wells in the areas indicated. Natural Gas
    
    
    Oil
    
    
    TotalGross
    
    
    Net
    
     
   Gross
    
    
    Net
    
    
    Gross
    
    
    NetTexas Gulf Coast
    
    
    43
    
    
    
    14.6
    
    
    
    19
    
    
    
    4.6
    
    
    
    62
    
    
    
    19.2Anadarko Basin
    
    
    103
    
    
    
    23.7
    
    
    
    19
    
    
    
    4.8
    
    
    
    122
    
    
    
    28.5West Texas
    
    
    15
    
    
    
    1.7
    
    
    
    83
    
    
    
    25.2
    
    
    
    98
    
    
    
    26.9Total
    
    
    161
    
    
    
    40.0
    
    
    
    121
    
    
    
    34.6
    
    
    
    282
    
    
    
    74.6
 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, two had multiple completions. 14




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##### Table of Contents



Acreage


Undeveloped acreage includes leased acres on which wells have not been drilled
or completed to a point that would permit the production of commercial
quantities of oil and natural gas, regardless of whether or not such acreage
contains proved reserves. The following table sets forth the approximate
developed and undeveloped acreage that we held a leasehold, mineral or other
interest at December 31, 2003:

Developed
    
    
    Undeveloped
    
    
    TotalGross
    
    
    Net
    
    
    Gross
    
    
    Net
    
    
    Gross
    
    
    NetTexas Gulf Coast
    
    
    9,785
    
    
    
    3,468
    
    
    
    16,948
    
    
    
    8,097
    
    
    
    26,733
    
    
    
    11,565Anadarko Basin
    
    
    40,006
    
    
    
    14,215
    
    
    
    37,278
    
    
    
    19,598
    
    
    
    77,284
    
    
    
    33,813West Texas
    
    
    9,681
    
    
    
    3,034
    
    
    
    9,006
    
    
    
    4,365
    
    
    
    18,687
    
    
    
    7,399Other
    
    
    1,521
    
    
    
    686
    
    
    
    3,483
    
    
    
    1,225
    
    
    
    5,004
    
    
    
    1,911Total
    
    
    60,993
    
    
    
    21,403
    
    
    
    66,715
    
    
    
    33,285
    
    
    
    127,708
    
    
    
    54,688


All the leases for the undeveloped acreage summarized in the preceding table
will expire at the end of their respective primary terms unless the existing
leases are renewed, production has been obtained from the acreage subject to
the lease prior to that date, or some other savings clause is implicated. The
following table sets forth the minimum remaining terms of leases for the gross
and net undeveloped acreage:

Acres ExpiringTwelve Months Ending:
    
    Gross
    
    
    NetDecember 31, 2004
    
    
    39,850
    
    
    
    13,320December 31, 2005
    
    
    12,885
    
    
    
    6,749December 31, 2006
    
    
    12,244
    
    
    
    8,564Thereafter
    
    
    323
    
    
    
    321Total
    
    
    65,302
    
    
    
    28,954




In addition, as of December 31, 2003, we had lease options to acquire
additional acres. The following table sets forth the year in which our options
expire and the gross and net acres we have under option: Acres ExpiringTwelve Months Ending:
    
    Gross
    
    
    NetDecember 31, 2004
    
    
    22,401
    
    
    
    13,338December 31, 2005
    
    
    6,482
    
    
    
    459Total
    
    
    28,883
    
    
    
    13,797
 15




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##### Table of Contents



Volumes, Prices and Production Costs The following table sets forth the production volumes, average prices received
before hedging, average prices received after hedging and average production
costs associated with our sale of oil and natural gas for the periods
indicated. Year Ended December 31,2003
    
    
    2002
    
    
    2001Production:Natural gas (MMcf)
    
    
    6,356
    
    
    
    5,791
    
    
    
    6,766Oil (MBbls)
    
    
    720
    
    
    
    701
    
    
    
    468Natural gas equivalent (MMcfe)
    
    
    10,674
    
    
    
    9,996
    
    
    
    9,573Average sales price per unit:Natural gas revenues (per Mcf)
    
    $
    5.68
    
    
    $
    3.33
    
    
    $
    4.29Effects of hedging activities (per Mcf)
    
    
    (0.76
    )
    
    
    (0.12
    )
    
    
    (1.18
    )Average price (per Mcf)
    
    $
    4.92
    
    
    $
    3.21
    
    
    $
    3.11Oil revenues (per Bbl)
    
    $
    30.79
    
    
    $
    25.17
    
    
    $
    24.38Effects of hedging activities (per Bbl)
    
    
    (2.62
    )
    
    
    (1.62
    )
    
    
    (0.33
    )Average price (per Bbl)
    
    $
    28.17
    
    
    $
    23.55
    
    
    $
    24.05Total natural gas and oil revenues (per Mcfe)
    
    $
    5.46
    
    
    $
    3.70
    
    
    $
    4.22Effects of hedging activities (per Mcfe)
    
    
    (0.63
    )
    
    
    (0.19
    )
    
    
    (0.85
    )Average price (per Mcfe)
    
    $
    4.83
    
    
    $
    3.51
    
    
    $
    3.37Average production costs:Lease operating expenses (per Mcfe)
    
    $
    0.43
    
    
    $
    0.31
    
    
    $
    0.32Ad valorem taxes (per Mcfe)
    
    
    0.06
    
    
    
    0.06
    
    
    
    0.05Production taxes (per Mcfe)
    
    
    0.23
    
    
    
    0.20
    
    
    
    0.16
 Costs Incurred The costs incurred in oil and natural gas acquisition, exploration and
development activities are as follows: Year Ended December 31,2003(a)
    
    
    2002(b)
    
    
    2001(c)(dollars in thousands)Exploration
    
    $
    20,732
    
    
    $
    12,693
    
    
    $
    18,210Property acquisition
    
    
    5,037
    
    
    
    3,213
    
    
    
    3,437Development
    
    
    22,285
    
    
    
    13,301
    
    
    
    14,353Proceeds from participants
    
    
    (793
    )
    
    
    (703
    )
    
    
    (135
    )Costs incurred
    
    $
    47,261
    
    
    $
    28,504
    
    
    $
    35,865
    (a)
    
    Excludes $427,000 of proceeds from the sale of interests in properties,
projects and prospects in 2003.(b)
    
    Excludes $821,000 of proceeds from the sale of interests in properties,
projects and prospects in 2002.(c)
    
    Excludes $262,000 of proceeds from the sale of interests in properties,
projects and prospects in 2001. Costs incurred represent amounts we incurred for exploration, property
acquisition and development activities. Periodically, we receive reimbursement
of certain costs from participants in our projects subsequent to project
initiation in return for an interest in the project. These payments are
described as Proceeds from participants in the table above. 16




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##### Table of Contents



ITEM 3. LEGAL PROCEEDINGS We are, from time to time, party to certain lawsuits and claims arising in the
ordinary course of business. While the outcome of lawsuits and claims cannot be
predicted with certainty, management does not expect these matters to have a
materially adverse effect on our financial condition, results of operations or
cash flows. On November 20, 2001, we filed a lawsuit in the
District Court of Travis
County, Texas, against Steve Massey Company, Inc. The Petition claims Massey
furnished defective casing to us, which ultimately led to the casing failure of
our Palmer 347 #5 well and the loss of the Palmer #5 as a producing
well. In 2004, the
parties agreed in principle to settle the case on terms favorable to us.
We will receive approximately $440,000 as a result of
this settlement. The amount of the settlement will reduce capitalized
well cost. In addition, Massey has agreed to drop its $445,819
counterclaim. On July 11, 2002, an employee of a contractor on
our Burkhart #1-R location,
Matagorda County, Texas, was involved in a fatal accident. The United States
Department of Labor Occupational Safety & Health Administration conducted an
inspection and we settled all issues resulting from that inspection for $70,000
in October 2003. On October 8, 2002, relatives of the
contractors employee filed a wrongful
death action against us and three other contractors in the District
Court of
Matagorda County, Texas. On March 23, 2004, a jury determined that we had no
liability in the accidental death of the contractors employee. In September 2002, we filed suit
in the District Court of Matagorda County,
Texas, against one of our contractors in connection with the drilling of the
Burkhart #1-R well, claiming that contractor breached its contract with us and
negligently performed services on the well. We believe the contractors
actions damaged us by approximately $650,000. The contractor counterclaimed,
claiming it is entitled to recover approximately $315,000. In
February 2004, the parties agreed in principle to settle the case. The settlement will result in a payment
by the contractor to our co-participants and us. In addition, the contractor
will drop its counterclaim. Based on the amount of the settlement, the
additional costs that were covered by insurance, and the insurer being
subrogated to our claim, we will not receive any incremental recovery as a
result of the settlement. Prior to drilling, the operator of the
Stonehocker #1 well disputed our
ownership in the well. In March 2003, a Motion to Determine election was filed
with the Oklahoma Corporation Commission. In January 2004, an Administrative
Law Judge with the Oklahoma Corporation Commission ruled in our favor. The
operator of the Stonehocker #1 appealed the ruling and the Appellate Referee
with the Oklahoma Corporation Commission affirmed the original ruling in March
2004. The full Commission Panel will review the reports of the Referee and the
original Administrative Law Judge and either approve or modify the report. An
order will then be issued reflecting the Oklahoma Corporation Commission ruling.
The operator will then have 30 days from the date of the final order to file an
appeal with the Oklahoma Supreme Court. A company that relinquished its ownership interest in the Nold #1S well as a
result of a non-consent election in the re-completion of the well has asserted
that it did not relinquish its entire interest, but rather became subject only
to a 400 percent payout provision. In November 2003, the company filed a
lawsuit in the District Court of Brazoria County, Texas, against us for breach
of contract. If the suit is successful, it could result in a judgment of as
much as $700,000. At this point in time, we cannot predict the outcome of this
case. In December 2003, we filed a lawsuit in the United States District Court for
the Western District of Texas against another company and a former employee
concerning the defendants misappropriation of our trade secrets and breach of
confidentiality obligations. We are seeking recovery of our damages and
injunctive relief. Defendants have denied any wrongdoing and have asserted a
counterclaim against us for alleged tortuous interference with an existing
business relationship between the company and its employee. The counterclaim
does not specify the amount of damages claimed other than that the damages
exceed $75,000 (the jurisdictional limit). At this point in time, we cannot
predict the outcome of this case. As of December 31, 2003, there are no known environmental or other regulatory
matters related to our operations that are reasonably expected to result in a
material liability to us. Compliance with environmental laws and regulations
has not had, and is not expected to have, a material adverse effect on our
capital expenditures. 
 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS No matter was submitted to a vote of our security holders during the fourth
quarter of 2003. 17




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##### Table of Contents



EXECUTIVE OFFICERS OF THE REGISTRANT Pursuant to Instruction 3 to Item 401(b) of the Regulation S-K and General
Instruction G(3) to Form 10-K, the following information is included in Part I
of this report. The following are our executive officers as of March 26, 2004. Name
    
    Age
    
    PositionBen M. Brigham
    
    
    44
    
    
    Chief Executive Officer, President and ChairmanEugene B. Shepherd, Jr.
    
    
    45
    
    
    Executive Vice President and Chief Financial OfficerDavid T. Brigham
    
    
    43
    
    
    Executive Vice PresidentLand and Administration and DirectorA. Lance Langford
    
    
    41
    
    
    Executive Vice PresidentOperationsJeffery E. Larson
    
    
    45
    
    
    Executive Vice PresidentExploration
 Ben M. Bud Brighamhas served as our Chief Executive Officer, President and
Chairman of the Board since we were founded 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, Inc. a provider of 3-D seismic services, after earning his B.S. in
Geophysics from the University of Texas. Mr. Brigham is the brother of David T.
Brigham, Executive Vice PresidentLand and Administration. Eugene B. Shepherd, Jr.has served as Executive Vice President since September
2003 and Chief Financial Officer since June 2002. Mr. Shepherd has
approximately 20 years of financial and operational experience in the energy
industry. Prior to joining us, Mr. Shepherd served as Integrated Energy
Managing Director at ABN AMRO Bank, a large European bank, where he executed
merger and acquisition advisory, capital markets and syndicated loan
transactions for energy companies. From July 1998 to August 2000, Mr. Shepherd
was an investment banking Director for Prudential Securities Incorporated,
where he executed a wide range of transactions for energy companies. Prior to
joining Prudential Securities Incorporated, Mr. Shepherd served as an
investment banker with Stephens Inc. from 1990 to June 1998 and with Merrill
Lynch Capital Markets from 1986 to 1990. Prior to joining Merrill Lynch Capital
Markets, Mr. Shepherd worked for over four years as a petroleum engineer for
both Amoco Production Company and the Railroad Commission of Texas. He has a
B.S. in Petroleum Engineering and an MBA, both from the University of Texas at
Austin. David T. Brighamjoined us in 1992 and has served as a Director since May 2003,
and as Executive Vice PresidentLand and Administration since June 2002. Mr.
Brigham served as Senior Vice PresidentLand and Administration from March 2001
to June 2002, Vice PresidentLand and Administration from February 1998 to
March 2001, as Vice PresidentLand and Legal from 1994 until February 1998 and
as Corporate Secretary from February 1998 to September 2002. From 1987 to 1992,
Mr. Brigham was an oil and gas attorney with Worsham, Forsythe, Sampels &
Wooldridge. Before attending law school, Mr. Brigham was a landman for Wagner &
Brown Oil and Gas Producers, an independent oil and gas exploration and
production company. Mr. Brigham holds a B.B.A. in Petroleum Land Management
from the University of Texas and a J.D. from Texas Tech School of Law. Mr.
Brigham is the brother of Ben M. Brigham, Chief Executive Officer, President
and Chairman of the Board. A. Lance Langfordjoined us in 1995 as Manager of Operations and served as Vice
PresidentOperations from January 1997 to March 2001, served as Senior Vice
PresidentOperations from March 2001 to September 2003 and has served as
Executive Vice PresidentOperations since September 2003. 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. Jeffery E. Larsonjoined us in 1997 and was Vice PresidentExploration from
August 1999 to March 2001, Senior Vice PresidentExploration from March 2001 to
September 2003 and has served as Executive Vice PresidentExploration since
September 2003. Prior to joining us, Mr. Larson was an explorationist in the
Offshore Department of Burlington Resources, a large independent exploration
company, where he was responsible for generating exploration and development
drilling opportunities. Mr. Larson worked at Burlington from 1990 to 1997 in
various roles of responsibility. Prior to Burlington, Mr. Larson spent five
years at Exxon as a Production Geologist and Research Scientist. He has a B.S.
in Earth Science from St. Cloud State University in Minnesota and a M.S. in
Geology from the University of Montana. 18




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##### Table of Contents



PART II 
 ITEM 5. MARKET FOR REGISTRANTS COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Price Range of Common Stock and Dividend Policy Our common stock commenced trading on the Nasdaq National Market on May 8, 1997
under the symbol BEXP. The following table sets forth the high and low
intra-day sales prices per share of our common stock for the periods indicated
on the Nasdaq National Market for the periods indicated. The sales information
below reflects inter-dealer prices, without retail mark-ups, mark-downs or
commissions and may not necessarily represent actual transactions. High
    
    Low2002:First Quarter
    
    
    3.970
    
    
    
    2.360Second Quarter.
    
    
    5.350
    
    
    
    3.420Third Quarter
    
    
    4.800
    
    
    
    3.100Fourth Quarter.
    
    
    5.000
    
    
    
    3.3002003:First Quarter
    
    
    6.000
    
    
    
    4.400Second Quarter.
    
    
    5.740
    
    
    
    4.500Third Quarter
    
    
    7.200
    
    
    
    4.750Fourth Quarter.
    
    
    8.410
    
    
    
    6.260
 The closing market price of our common stock on March 26, 2004 was $6.78 per
share. As of March 26, 2004, there were an estimated 122 record owners of our
common stock. No dividends have been declared or paid on our common stock to date. We intend
to retain all future earnings for the development of our business. Our senior
credit facility, senior subordinated notes and Series A preferred stock
restrict our ability to pay dividends on our common stock. We are obligated to pay dividends on our Series A preferred stock. At our
option, these dividends may be paid in cash at a rate of 6% per annum or paid
in kind through the issuance of additional shares of preferred stock in lieu of
cash at a rate of 8% per annum. Our option to pay dividends in kind on our
Series A preferred stock expires in October 2005. See Item 7. Managements
Discussion and Analysis of Financial Condition and Results of
OperationsCapital CommitmentsMandatorily Redeemable Preferred Stock. 19




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##### Table of Contents



Securities Authorized for Issuance under Equity Compensation Plans The following table includes information regarding our equity compensation
plans as of the year ended December 31, 2003: Number ofsecuritiesNumber of
    
    
    
    
    
    
    remainingsecurities
    
    
    
    
    
    
    availableto be issued upon
    
    
    Weighted-average
    
    
    for future issuanceexercise of
    
    
    price of
    
    
    under equityoutstanding
    
    
    outstanding
    
    
    compensationPlan category
    
    options
    
    
    options
    
    
    plansEquity compensation
plans approved by
security holders
(a)
    
    
    2,582,675
    
    
    $
    4.78
    
    
    
    1,080,296Equity compensation
plans not approved
by security holders
    
    
    
    
    
    
    
    
    
    
    Total
    
    
    2,582,675
    
    
    $
    4.78
    
    
    
    1,080,296
 
 (a)
    
    Does not include 411,171 shares of restricted stock at December 31, 2003. Recent Issuance of Unregistered Securities Common Stock All shares of common stock issued in the following transactions were exempted
from registration under section 4(2) of the Securities Act of 1933. In December 2002, we issued 550,000 unregistered shares of our common stock to
Shell Capital. The common stock was issued in exchange for Shell Capitals
warrant position, including 1,250,000 warrants associated with our senior
subordinated notes facility, and to terminate its right to convert $30 million
of our senior credit facility into 5,480,769 shares of our common stock. Shell
Capital subsequently sold these shares in our common stock sale in September
2003 and we received no proceeds from the sale of the common stock. In December 2002, we issued 243,902 unregistered shares of our common stock to
a group of institutional investors led by affiliates of two members of our
board of directors. The common stock was issued to the group in connection
with its cash exercise of warrants to purchase 243,902 shares of our common
stock for $2.5625 per share. We received cash proceeds $625,000 from the
exercise. The warrants exercised represented a portion of the warrants that
were issued in connection with our sale of 731,707 shares of our common stock
in February 2000. The remaining warrants were exercised in February 2003. In February 2003, we issued 248,028 unregistered shares of our common stock to
a group of institutional investors led by affiliates of two of our board
members. The common stock was issued to the group in connection with its
cashless exercise of warrants to purchase 487,805 shares of our common stock
for $2.5625 per share. We received no proceeds from the warrant exercise. The
warrants exercised represented a portion of the warrants that were issued in
connection with our sale of 731,707 shares of our common stock in February
2000. In June 2003, we issued 408,928 unregistered shares of our common stock to the
Bank of Montreal. The common stock was issued to the Bank of Montreal in
connection with its cashless exercise of warrants to purchase 661,538 shares of
our common stock for $2.02 per share. We received no proceeds from the warrant
exercise. The warrants were issued as consideration for an amendment to a
previous senior credit facility in July 1999. The original warrant exercise
price of $2.25 per share was reset to $2.02 in February 2000 in connection with
an amendment to a previous senior credit facility. The Bank of Montreal
subsequently sold these shares in our common stock sale in September 2003 and
we received no proceeds from the sale of the common stock. In June 2003, we issued 206,982 unregistered shares of our common stock to
Société Générale. The common stock was issued to Société Générale in
connection with its cashless exercise of warrants to purchase 338,462 shares of
our common stock for $2.02 per share. We received no proceeds from the warrant
exercise. The warrants were issued as consideration for an amendment to a
previous senior credit facility in July 1999. The original warrant exercise
price of $2.25 per share was reset to $2.02 in February 2000 in connection with
an amendment to a previous senior credit facility. Société Générale
subsequently sold these shares in our common
stock sale in September 2003 and we received no proceeds from the sale of the
common stock. 20




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##### Table of Contents



In November 2003, we issued 6,666,667 unregistered shares of our common stock
to CSFB Private Equity. The common stock was issued to CSFB Private Equity in
connection with its exercise of warrants to purchase 6,666,667 shares of our
common stock for $3.00 per share. Pursuant to the warrant agreement, we
required CSFB Private Equity to exercise the warrants as the average price of
our common stock closed above $5.00 per share each day for 60 consecutive days.
CSFB Private Equity elected to use 1,000,002 shares of Series A
preferred stock to pay the $20 million exercise price. The warrants were
issued in connection with our sale of $20 million of Series A  Tranche 1
preferred stock to CSFB Private Equity in November 2000. In December 2003, we issued 2,105,263 unregistered shares of our common stock
to CSFB Private Equity. The common stock was issued to CSFB Private Equity in
connection with its exercise of warrants to purchase 2,105,263 shares of our
common stock for $4.35 per share. The original exercise price for the warrants
was $4.75, but was reset in December 2002, in connection with the issuance of
our Series B preferred stock. Pursuant to the warrant agreement, we required
CSFB Private Equity to exercise the warrants as our stock price averaged at
least $6.525 (150% of the exercise price of the warrants) for 60 consecutive
trading days. CSFB Private Equity elected to use 457,898 shares of Series A
preferred stock to pay the $9.2 million exercise price and we received no
proceeds from the warrant exercise. The warrants were issued in connection
with our sale of $10 million of Series A  Tranche 2 preferred stock to CSFB
Private Equity in March 2001. See  Mandatorily Redeemable Preferred Stock. In December 2003, we issued 2,298,850 unregistered shares of our common stock
to CSFB Private Equity. The common stock was issued to CSFB Private Equity in
connection with its exercise of warrants to purchase 2,298,850 shares of our
common stock for $4.35 per share. Pursuant to the warrant agreement, we
required CSFB Private Equity to exercise the warrants as our stock price
averaged at least $6.525 (150% of the exercise price of the warrants) for 60
consecutive trading days. CSFB Private Equity elected to use 500,002 shares of
Series B preferred stock to pay the $10 million exercise price and we received
no proceeds from the warrant exercise. The warrants were issued in connection
with our sale of $10 million of Series B preferred stock to CSFB Private Equity
in December 2002. See  Mandatorily Redeemable Preferred Stock. Mandatorily Redeemable Preferred Stock All shares of mandatorily redeemable preferred stock issued in the following
transactions were exempted from registration under section 4(2) of the
Securities Act of 1933. In March 2001, we issued to CSFB Private Equity 500,000 shares of our Series A
 Tranche 2 preferred stock with a stated value of $20.00 per share. Net
proceeds from the offering were $9.8 million and were used to fund our
exploration and development activities and working capital
requirements. The Series A 
Tranche 2 preferred stock has terms similar to
our previously issued Series A preferred stock. We are required to pay dividends on our Series A
preferred stock at a rate of 6% per annum if paid in cash or 8% per
annum if paid
in kind through the issuance of additional shares of preferred stock in lieu of
cash. Our option to pay dividends in kind expires in October 2005. In
connection with the issuance of the Series A  Tranche 2 preferred stock, we
issued to CSFB Private Equity warrants to purchase 2,105,263 shares of our
common stock at an exercise price of $4.75 per share. The original exercise
price for the warrants was reset in December 2002, in connection with the
issuance of our Series B preferred stock. To exercise the warrants, CSFB
Private Equity had the option to use either cash or shares of Series A
preferred stock with an aggregate value equal to the exercise price.
In December 2003, CSFB Private Equity elected to use 457,898
shares of Series A
preferred stock to pay the $9.2 million warrant exercise price.
See Common Stock. In December 2002, we issued to
CSFB Private Equity 500,000 shares of our Series
B preferred stock with a stated value of $20.00 per share. Net proceeds from
the offering were $9.4 million and were used to reduce borrowings under our
senior credit facility and to fund our drilling program and working capital
requirements. The Series B preferred stock has terms similar to our previously
issued Series A preferred stock. We were required to pay dividends on our
Series B preferred stock at a rate of 6% per annum if paid in cash or 8% per
annum if paid in kind through the issuance of additional shares of preferred stock
in lieu of cash. Our option to pay dividends in kind would have expired in December 2007.
In connection with the issuance of the Series B preferred stock, we issued to
CSFB Private Equity warrants to purchase 2,298,851 shares of our common stock
at an exercise price of $4.35 per share. To exercise the warrants, CSFB Private
Equity had the option to use either cash or shares of our Series B preferred
stock with an aggregate value equal to the exercise price. In December 2003,
CSFB Private Equity elected to use 500,002 shares of Series B preferred stock
to pay the $10 million warrant exercise price. See Common Stock. In
addition, pursuant to the terms of the Series B preferred stock we paid CSFB
Private Equity approximately $704,000 to redeem the shares of Series B
preferred stock that remained outstanding after the exercise. 21




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##### Table of Contents



ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA This section presents our selected consolidated financial data and should be
read in conjunction with Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations and our consolidated financial
statements and related notes included in Item 8. Financial Statements and
Supplementary Data. The selected consolidated financial data in this section
is not intended to replace the consolidated financial statements. We derived the statement of operations data and statement of cash flows data
for the years ended December 31, 2003, 2002 and 2001, and balance sheet data as
of December 31, 2003 and 2002 from the audited consolidated financial
statements included in this report. We derived the statement of operations data
and statement of cash flows data for the years ended December 31, 2000 and 1999
and the balance sheet data as of December 31, 2001, 2000 and 1999 from audited
consolidated financial statements that are not included in this report. Year Ended December 31,2003
    
    
    2002
    
    
    2001
    
    
    2000
    
    
    1999(dollars in thousands, except per share information)Statement of Operations Data:Oil and natural gas sales
    
    $
    51,545
    
    
    $
    35,100
    
    
    $
    32,293
    
    
    $
    19,143
    
    
    $
    14,992Other revenues
    
    
    132
    
    
    
    76
    
    
    
    255
    
    
    
    69
    
    
    
    285Total revenues
    
    
    51,677
    
    
    
    35,176
    
    
    
    32,548
    
    
    
    19,212
    
    
    
    15,277Lease operating
    
    
    5,200
    
    
    
    3,759
    
    
    
    3,486
    
    
    
    2,139
    
    
    
    2,259Production taxes
    
    
    2,477
    
    
    
    1,977
    
    
    
    1,511
    
    
    
    1,786
    
    
    
    968General and administrative
    
    
    4,500
    
    
    
    4,971
    
    
    
    3,638
    
    
    
    3,100
    
    
    
    3,481Depletion of oil and natural
gas properties
    
    
    16,972
    
    
    
    14,594
    
    
    
    13,211
    
    
    
    7,920
    
    
    
    7,792Depreciation and amortization
    
    
    629
    
    
    
    440
    
    
    
    677
    
    
    
    620
    
    
    
    526Accretion of discount on asset
retirement obligations
    
    
    142
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Loss on sale of oil and natural
gas properties
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    12,195Total costs and expenses
    
    
    29,920
    
    
    
    25,741
    
    
    
    22,523
    
    
    
    15,565
    
    
    
    27,221Operating income (loss)
    
    
    21,757
    
    
    
    9,435
    
    
    

    10,025
    
    
    
    3,647
    
    
    
    (11,944
    )Other income (expense)Interest expense, net
    
    
    (4,815
    )
    
    
    (6,238
    )
    
    
    (6,681
    )
    
    
    (9,906
    )
    
    
    (9,697
    )Interest income
    
    
    45
    
    
    
    119
    
    
    
    264
    
    
    
    108
    
    
    
    176Other income (expense)
    
    
    (601
    )
    
    
    (310
    )
    
    
    8,080
    
    
    
    (9,504
    )
    
    
    (163
    )Debt conversion expense
    
    
    
    
    
    
    (630
    )
    
    
    
    
    
    
    
    
    
    
    Gain on refinancing of debt
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    32,267
    
    
    
    Total other income (expense)
    
    
    (5,371
    )
    
    
    (7,059
    )
    
    
    1,663
    
    
    
    12,965
    
    
    
    (9,684
    )Income (loss) before income
taxes and cumulative effect of
change in accounting principle
    
    $
    16,386
    
    
    $
    2,376
    
    
    $
    11,688
    
    
    $
    16,612
    
    
    $
    (21,628
    )Income tax benefit
    
    
    1,636
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Income (loss) before
cumulative effect of change
in accounting principle
    
    
    18,022
    
    
    
    2,376
    
    
    
    11,688
    
    
    
    16,612
    
    
    
    (21,628
    )Cumulative effect of change in
accounting principle
    
    
    268
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Net income (loss)
    
    
    18,290
    
    
    
    2,376
    
    
    
    11,688
    
    
    
    16,612
    
    
    
    (21,628
    )Preferred dividend and accretion
    
    
    3,448
    
    
    
    2,952
    
    
    
    2,450
    
    
    
    275
    
    
    
    Net income (loss) available
to common stockholders
    
    $
    14,842
    
    
    $
    (576
    )
    
    $
    9,238
    
    
    $
    16,337
    
    
    $
    (21,628
    )Net income (loss) per share
before cumulative effect of
change in accounting principleBasic
    
    $
    0.63
    
    
    $
    (0.04
    )
    
    $
    0.58
    
    
    $
    1.01
    
    
    $
    (1.53
    )Diluted
    
    
    0.52
    
    
    
    (0.04
    )
    
    
    0.44
    
    
    
    1.01
    
    
    
    (1.53
    )Weighted avg. shares
outstandingBasic
    
    
    23,363
    
    
    
    16,138
    
    
    
    15,988
    
    
    
    16,241
    
    
    
    14,152Diluted
    
    
    34,354
    
    
    
    16,138
    
    
    
    28,205
    
    
    
    16,241
    
    
    
    14,152
 22




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##### Table of Contents



At December 31,2003
    
    
    2002
    
    
    2001
    
    
    2000
    
    
    1999(dollars in thousands)Statement of Cash Flows Data:Net cash provided (used) by:Operating activities
    
    $
    41,691
    
    
    $
    28,973
    
    
    $
    18,922
    
    
    $
    (4,635
    )
    
    $
    2,578Investing activities
    
    
    (46,089
    )
    
    
    (27,206
    )
    
    
    (33,571
    )
    
    
    (26,071
    )
    
    
    1,644Financing activities
    
    
    (5,141
    )
    
    
    8,439
    
    
    
    18,924
    
    
    
    28,801
    
    
    
    (4,049
    )Balance Sheet Data:Cash and cash equivalents
    
    $
    5,779
    
    
    $
    15,318
    
    
    $
    5,112
    
    
    $
    837
    
    
    $
    2,742Oil and natural gas properties, net
    
    
    197,311
    
    
    
    164,980
    
    
    
    151,891
    
    
    
    129,490
    
    
    
    112,066Total assets
    
    
    224,216
    
    
    
    202,059
    
    
    
    173,075
    
    
    
    146,911
    
    
    
    125,683Long-term debt
    
    
    39,000
    
    
    
    81,797
    
    
    
    91,721
    
    
    
    82,000
    
    
    
    97,341Series A preferred stock,
mandatorily redeemable
    
    
    8,794
    
    
    
    19,540
    
    
    
    16,614
    
    
    
    8,558
    
    
    
    Series B preferred stock,
mandatorily redeemable
    
    
    
    
    
    
    4,777
    
    
    
    
    
    
    
    
    
    
    
    Total stockholders equity
    
    
    138,345
    
    
    
    61,749
    
    
    
    49,601
    
    
    
    34,757
    
    
    
    8,998
 23




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##### Table of Contents



ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Statements in the following discussion may be forward-looking and involve risk
and uncertainty. The following discussion should be read in conjunction with
our Consolidated Financial Statements and Notes hereto. Overview We are an independent exploration and production company that applies 3-D
seismic imaging and other advanced technologies to systematically explore for
and develop onshore oil and natural gas reserves in the United States. Our
activities are concentrated in the onshore Texas Gulf Coast, the Anadarko Basin
and West Texas, which are areas with known hydrocarbon resources, which are
conducive to multi-well, repeatable drilling programs and the skills of our
technical staff. Our principal business is the generation of drilling prospects in our core
provinces, the drilling of those prospects and, if successful, the subsequent
completion and production of the resulting oil or natural gas well. We do not
have a history of aggressively competing for acquisition opportunities,
although we regularly review such opportunities. We believe that we can
achieve a better and more predictable rate of return by focusing our activities
on prospect generation, drilling and producing activities. To support our prospect generation activities, we allocate a portion of our
capital expenditures to land, geophysical and geological activities. Over the
past three years capital expenditures for land, geophysical and geological
activities represented 12% of our total capital expenditures. For 2004, we
expect to spend approximately 15% of our total capital expenditures on land,
geophysical and geological activities. The capital that funds our drilling activities is allocated to individual
prospects based on the value potential of a prospect, as measured by a risked
net present value analysis. We start each year with a budget and reevaluate
this budget monthly. The primary factors that impact this value creation
measure include forecasted commodity prices, drilling and completion costs, and
a prospects risked reserve size and risked initial producing rate. Other
factors that are also monitored throughout the year that influence the amount
and timing of our drilling expenditures include the level of production from
our existing oil and natural gas properties, the availability of drilling and
completion services, and the success and resulting production of our newly
drilled wells. The outcome of our monthly analysis results in a
reprioritization of our exploration and development well drilling schedule to
ensure that we are optimizing our capital expenditure plan. Over the past three years, we have spent approximately $33 million to drill 48
exploratory wells, which represents 30% of our total capital expenditures for
that time period. For 2004, we currently plan to spend approximately $22
million, or 28% of our total budgeted capital expenditures to drill 23
exploratory wells. We believe that we possess a multi-year inventory of
exploratory drilling prospects, the majority of which have been internally
generated by our staff. As a consequence and considering the results that we
have achieved in recent years, we expect that we will continue to emphasize our
prospect generation and drilling strategy as our primary means of creating
value for our shareholders. Over the past three years we
have spent approximately $49.1 million to drill 45
development wells, which represents 45% of our total capital expenditures for
that time period. Due to our exploratory drilling success, over the last four
years, a growing percentage of our capital expenditures have been allocated to
the development of our six significant field discoveries. We expect this trend
to continue, and for 2004 currently plan to spend approximately $39.4 million,
or 50% of our total budgeted capital expenditures to drill 36 development
wells. 2003 Highlights During 2003, we achieved several financial and operational milestones.
The following are some of the highlights for 2003.  
    
    Our average daily production for 2003 was 29.7 MMcfe/d and increased
7% over average daily production in 2002.
    
    We added approximately 23.8 Bcfe of proved reserves, of which 20 Bcfe
were proved developed, growing our estimated net proved reserve volumes
by 11% and replacing 223% of our 2003 production.
    
    We made a new field discovery at Floyd South.
    
    We expanded our Diablo Project area with two new joint ventures.
    
    We acquired two new 3-D seismic data sets in the Gulf Coast, which
have already generated four discoveries in four attempts.
    
    We reported operating income of $21.8 million, up 131% when compared to operating income for 2002.
    
    Our earnings for 2003 were $0.53 per diluted share relative to a net loss of $0.04 in 2002. 24




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
    
    Our common stock offering in September 2003, combined with the
exercise of the Series A and Series B warrants and our earnings,
improved our balance sheet and strengthened our overall financial
position by reducing our total debt to capitalization ratio from 63% at
December 31, 2002 to 27% at December 31, 2003.
    
    In November 2003, we significantly increased our drilling
expenditures. We plan to use the availability under our senior credit
facility, along with our internally generated cash flow and cash on
hand, to accelerate our drilling activities in the current environment
of high commodity prices and relatively low service costs. 2004 Outlook Our total net capital spending budget for 2004 is $79 million. The majority of
our planned 2004 expenditures will be directed toward the drilling of our
exploration and development inventory to focus resources on our primary
objective of growing our reserves, production volumes and cash flow. For 2004,
we expect to drill 59 (36 development and 23 exploratory) wells with an average
working interest of approximately 42%. Capitalizing on our prior discoveries,
including the Home Run, Mills Ranch, Triple Crown, Floyd Fault Block, Floyd
South Fault Block and Providence Fields, approximately 64% of our 2004 drilling
expenditures are allocated to development drilling. Our current cash balance,
cash flow from operations and availability under our senior credit facility,
will fund our spending. Estimated net capital expenditures for 2004 represent
an increase of approximately 61% over the amount that we spent in 2003. The
final determination with respect to our 2004 budgeted expenditures will depend
on a number of factors, including:  
    
    commodity prices;
    
    production from our existing producing wells;
    
    the results of our current exploration and development drilling efforts;
    
    economic and industry conditions at the time of drilling, including the availability of drilling equipment; and
    
    the availability of more economically attractive prospects. There can be no assurance that the budgeted wells will, if drilled, encounter
commercial quantities of natural gas or oil. Statements in this section include forward-looking statements. See
Forward-Looking Statements. Critical Accounting Policies The establishment and consistent application of accounting policies is a vital
component of accurately and fairly presenting our consolidated financial
statements in accordance with generally accepted accounting principles (GAAP),
as well as ensuring compliance with applicable laws and regulations governing
financial reporting. While there are rarely alternative methods or rules from
which to select in establishing accounting and financial reporting policies,
proper application often involves significant judgment regarding a given set of
facts and circumstances and a complex series of decisions. Property and Equipment The method of accounting for oil and natural gas properties is a critical
accounting policy because it determines what costs are capitalized, and how
these costs are ultimately matched with revenues and expensed. We use the full cost method of accounting for oil and natural gas properties.
Under this method substantially all costs associated with oil and natural gas
exploration and development activities are capitalized, including costs for
individual exploration projects that do not directly result in the discovery of
hydrocarbon reserves that can be economically recovered. A portion of the
payroll, interest, and other internal costs we incur for the purpose of finding
hydrocarbon reserves are also capitalized. Full cost pool amounts associated with properties that have been evaluated
through drilling or seismic analysis are depleted using the units of production
method. The depletion expense per unit of production is the ratio of
unamortized historical and estimated future development costs to proven
hydrocarbon reserve volumes. Estimation of hydrocarbon reserves relies on
professional judgment and use of factors that cannot be precisely determined.
Subsequent reserve estimates materially different from those reported would
change the depletion expense recognized during the future reporting period. For
the year ended December 31, 2003, our depletion expense per unit of production
was $1.59 per Mcfe. A change of 900,000 Mcfe in our estimated net proved
reserves at December 31, 2003, would result in a $0.01 per Mcfe change in our
per unit depletion expense and a $107,000 change in our pre-tax net
income. To the extent costs capitalized in the full cost pool (net of depreciation,
depletion and amortization and related deferred taxes) exceed the present value
(using a 10% discount rate and based on period-end hedge adjusted oil and
natural gas prices) of estimated future net 25




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##### Table of Contents



cash flows from proved oil and
natural gas reserves plus the capitalized cost of unproved properties, such
costs are charged to operations as a reduction of the carrying value of oil and
natural gas properties, or a capitalized ceiling impairment charge. The risk
that we will be required to write down the carrying value of our oil and
natural gas properties increases when oil and natural gas prices are depressed,
even if the low prices are temporary. In addition, capitalized ceiling
impairment charges may occur if we experience poor drilling results or
estimations of proved reserves are substantially reduced. A capitalized ceiling impairment is a reduction in earnings that does not
impact cash flows, but does impact operating income and stockholders equity.
Once recognized, a capitalized ceiling impairment charge to oil and natural gas
properties cannot be reversed at a later date. No assurance can be given that
we will not experience a capitalized ceiling impairment charge in future
periods. In addition, capitalized ceiling impairment charges may occur if
estimates of proved hydrocarbon reserves are substantially reduced or estimates
of future development costs increase significantly. See Risk
FactorsExploratory Drilling Is A Speculative Activity That May Not Result In
Commercially Productive Reserves And May Require Expenditures In Excess Of
Budgeted Amounts, Risk FactorsThe Failure To Replace Reserves In The Future
Would Adversely Affect Our Production And Cash Flows and Risk FactorsWe Are
Subject To Uncertainties In Reserve Estimates And Future Net Cash Flows. Asset Retirement Obligations We have significant obligations to plug and
abandon oil and natural gas wells and related equipment. Liabilities for asset retirement obligations are
recorded at fair value in the period incurred. The related asset value is
increased by the same amount. Asset retirement costs included in the carrying
amount of the related asset are subsequently allocated to expense as part of
our depletion calculation. See Property and
Equipment.
Additionally, increases in the discounted asset retirement liability resulting
from the passage of time are reflected as accretion of discount on asset
retirement obligations expense in the Consolidated Statement of Income. Estimating future asset retirement obligations requires us to make estimates
and judgments regarding timing, existence of a liability, as well as what
constitutes adequate restoration. We use the present value of estimated cash
flows related to our asset retirement obligations to determine the fair value.
Present value calculations inherently incorporate numerous assumptions and
judgments. These include the ultimate retirement and restoration costs,
inflation factors, credit adjusted discount rates, timing of settlement, and
changes in the legal, regulatory, environmental and political environments. To
the extent future revisions to these assumptions impact the present value of
the existing asset retirement obligation liability, a corresponding adjustment
will be made to the carrying cost of the related asset. Income Taxes Deferred tax assets are recognized for temporary differences in financial
statement and tax basis amounts that will result in deductible amounts and
carry-forwards in future years. Deferred tax liabilities are recognized for
temporary differences that will result in taxable amounts in future years.
Deferred tax assets and liabilities are measured using enacted tax law and tax
rate(s) for the year in which we expect the temporary differences to be
deducted or settled. The effect of a change in tax law or rates on the
valuation of deferred tax assets and liabilities is recognized in income in the
period of enactment. Deferred tax assets are reduced by a valuation allowance
when, in the opinion of management, it is more likely than not that some
portion or all of the deferred tax assets will not be realized. Estimating the amount of the valuation allowance is dependent on estimates of
future taxable income, alternative minimum tax income, and changes in
stockholder ownership that would trigger limits on use of net operating losses
under Internal Revenue Code Section 382. We have a significant deferred tax asset associated with net operating loss
carryforwards (NOLs). It is more likely than not that we could begin using
these NOLs to offset current tax liabilities during 2004. Our NOLs are more
fully described in Notes to the Consolidated Financial
StatementsNote 9. Revenue Recognition We derive revenue primarily from the sale of produced oil and natural gas,
hence our revenue recognition policy for these sales is significant. We recognize crude oil revenue using the sales method of accounting. Under this
method, revenue is recognized when oil is delivered
and title transfers. We recognize natural gas revenue using the entitlements method of accounting.
Under this method, revenue is recognized based on 26




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##### Table of Contents



our entitled ownership
percentage of sales of natural gas delivered to purchasers. Gas imbalances
occur when we sell more or less than our entitled ownership percentage of total
natural gas production. When we receive less than our entitled share, a
receivable is recorded. When we receive more than our entitled share, a
liability is recorded. Settlements for hydrocarbon sales can occur up to two months after the end of
the month in which the oil, gas or other hydrocarbon products were produced. We
estimate and accrue for the value of these sales using information available at
the time financial statements are generated. Differences are reflected in the
accounting period that payments are received from the purchaser. Derivative Instruments and Hedging Activities We use derivative instruments to manage market risks resulting from
fluctuations in commodity prices of natural gas and crude oil. We periodically
enter into commodity contracts, including price swaps, caps and floors, which
require payments to (or receipts from) counterparties based on the differential
between a fixed price and a variable price for a fixed quantity of natural gas
or crude oil without the exchange of underlying volumes. The notional amounts
of these financial instruments are based on expected production from existing
wells. We similarly use derivative instruments to manage risks associated with
interest rate fluctuations on long term debt. During 2003 we entered into an
interest rate swap to convert the floating interest rate on our senior
subordinated notes to a fixed interest rate to reduce our exposure to
potentially higher interest rates in the future. The notional amount of this
hedge is equal to the amount of senior subordinated notes outstanding, and is
more fully described in Notes to the Consolidated Financial
StatementsNote 5 and Notes to the Consolidated Financial
StatementsNote 12. We adopted Statement of Financial Accounting Standards No. 133 (SFAS 133) on
January 1, 2001 in accordance with Financial Accounting Standards Board (FASB)
requirements. SFAS 133, as amended, establishes accounting and reporting
standards for derivative instruments and for hedging activities. All derivative
instruments are recorded on the balance sheet at fair value and changes in the
fair value of the derivatives are recorded each period in current earnings or
other comprehensive income, depending on whether a derivative is designated as
part of a hedge transaction, and depending on the type of hedge transaction.
Our derivative contracts are cash flow hedge transactions in which we are
hedging the variability of cash flow related to a forecasted transaction.
Changes in the fair value of these derivative instruments are reported in other
comprehensive income and reclassified as earnings in the period(s) in which
earnings are impacted by the variability of the cash flow of the hedged item.
We assess the effectiveness of hedging transactions every three months,
consistent with documented risk management strategy for the particular hedging
relationship. Changes in the fair value of the ineffective portion of hedges are
included in earnings. Use of Estimates The preparation of financial statements in accordance with generally accepted
accounting principles in the United States of America requires management to
make estimates and assumptions that affect reported assets, liabilities,
revenues, expenses, and some narrative disclosures. Hydrocarbon reserves,
future development costs, and certain hydrocarbon production expense and
revenue estimates are the most critical to our financial statements. New Accounting
Pronouncements In May 2003, the FASB issued Statement of Financial Accounting Standards No.
150, Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity (SFAS 150). SFAS 150 requires us to classify certain
financial instruments, such as mandatorily redeemable preferred stock, as
liabilities (or assets in some circumstances). We adopted this standard as
required on July 1, 2003. Upon adoption, approximately $8 million of
mandatorily redeemable Series A and B preferred stock was reclassified to
long-term debt. Dividends of approximately $340,000 on the reclassified amount
of mandatorily redeemable Series A and B preferred stock are included in our
Consolidated Statement of Operations as interest expense. Commodity Prices Changes in commodity prices significantly affect our capital resources,
liquidity and operating results. Price changes directly affect revenues and can
indirectly impact expected production by changing the amount of available
capital to reinvest in our exploration and
development activities. Commodity prices are impacted by many factors that are
outside of our control. Over the past couple of years, commodity prices have
been very volatile. We expect that commodity prices will continue to fluctuate
significantly in the future. As a result, we cannot accurately predict future
oil and natural gas prices, and therefore, we cannot determine what effect
increases or decreases will have on our capital program, production volumes and
future revenues. 27




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##### Table of Contents



The prices we receive for our crude oil production are based on global market
conditions. During 2003, oil prices increased in response to political unrest
and supply disruptions in the Middle East as well as other supply and demand
factors. Our average sales price for oil in 2003 was $30.79 per barrel, which
was 22% higher than the price we received in 2002. Significant factors that
will impact 2004 oil prices include developments in Iraq and other Middle East
countries, the extent to which members of the Organization of Petroleum
Exporting Countries and other oil exporting nations are able to manage oil
supply through export quotas.
North American market forces primarily drive the price we receive for our
natural gas production. Factors that can affect the price of natural gas are
changes in market demands, overall economic activity, weather, pipeline
capacity constraints, inventory storage levels, basis differentials and other
factors. Over the past two years natural gas prices have been volatile. The
average sales price that we received for natural gas in 2003 was $5.68 per Mcf,
which was 71% higher than the sales price that we received for sales in 2002.
The average sales price that we received for natural gas in 2002 was $3.33 per
Mcf, which was 22% lower than the sales price that we received in 2001. The
increase North American gas prices in 2003 were in response to strong supply
and demand fundamentals. Natural gas prices for 2004 will depend on variations
in key North American gas supply and demand indicators. Capital Commitments Our primary needs for cash are for the exploration and development of oil and
gas properties, repayment of contractual obligations and funding working
capital obligations. Funding for the exploration and development of oil and gas
properties and repayment of contractual obligations may be provided by any
combination of cash flow from operations, cash on our balance sheet, the unused
committed borrowing capacity under our senior credit facility, reimbursements
of prior land and seismic costs by participants in our projects and the sale of
interests in projects and properties or alternative financing sources as
discussed in Capital Resources and Liquidity. Funding for our working
capital obligations is provided by cash flows from operations and the unused
committed borrowing capacity under our senior credit facility. Contractual Obligations The following schedule summarizes our known contractual cash obligations at
December 31, 2003 and the effect such obligations are expected to have on our
liquidity and cash flow in future periods. Payments Due by YearTotal
    
    
    
    
    
    
    
    
    
    
    2006-
    
    
    2008 andOutstanding
    
    
    2004
    
    
    2005
    
    
    2007
    
    
    Thereafter(dollars in thousands)Senior credit facility (a)
    
    $
    19,000
    
    
    $
    
    
    
    $
    
    
    
    $
    19,000
    
    
    $
    Senior subordinated notes (b)
    
    
    20,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    20,000Mandatorily redeemable,
Series A preferred stock (c)
    
    
    8,794
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    8,794Non-cancelable operating leases (d)
    
    
    3,185
    
    
    
    910
    
    
    
    910
    
    
    
    1,365
    
    
    
    Total contractual cash obligations
    
    $
    50,979
    
    
    $
    910
    
    
    $
    910
    
    
    $
    20,365
    
    
    $
    28,794
    (a)
    
    Based on $19 million outstanding and an interest rate at December 31,
2003, of 2.7%, we would be required to pay $513,000 in interest per year
until our senior credit facility matures. This amount of interest will
fluctuate over time as borrowings under our senior credit facility
increase or decrease and as the applicable interest rate increases or
decreases. See Item 7A Quantitative and Qualitative Disclosures About
Market RiskQuantitative DisclosuresInterest Rate Risk.  (b)
    
    Based on $20 million outstanding and a current interest rate of 8.8%,
we would be required to pay $1.8 million in interest per year until our
senior subordinated notes mature.  (c)
    
    At our option, dividends on our Series A preferred stock may be paid
in cash at a rate of 6% per annum or paid in kind through the issuance
of additional shares of preferred stock in lieu of cash at a rate of 8%
per annum. Our option to pay dividends in kind expires in November 2005.
If we elect to pay the dividends in cash, based on $8.8 million
outstanding we
would be required to pay $528,000 in dividends per year until our
mandatorily redeemable Series A preferred stock matures. If we elect to
pay the dividends in kind, in 2004 we would be required issue
approximately 36,250 shares of additional Series A preferred to pay
dividends of $725,000. In 2005, we would be required to issue
approximately 32,483 shares of additional Series A preferred stock to pay
dividends of $649,660. The dividends in 2005 represents dividends on the
outstanding Series A preferred stock from January 1, 2005 to October 31,
2005, the expiration of our option to pay dividends in kind. Thereafter,
we would be required to pay an annual cash dividend of approximately
$610,000 until maturity. 28




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##### Table of Contents



(d)
    
    Not reduced by rental payments that we will receive from a
non-cancelable sublease of approximately $64,000 due in 2004 and $38,000
due in 2005. Senior Credit Facility As of December 31, 2003, we had $19 million in borrowings outstanding under our
senior credit facility. In March 2003, we replaced our then existing senior
credit facility with a new senior credit facility that provides for a maximum
$80 million in commitments and an initial committed borrowing base of $70
million and matures in March 2006. The collateral value and borrowing base are redetermined semi-annually and are
based in part on prevailing oil and natural gas prices. If, upon
redetermination, our borrowing base decreases, we may have to repay a portion
of our borrowings within 90 days, our access to further borrowings will be
reduced, and we may not have the resources necessary to carry out our planned
drilling activities. Based on the most recent determination effective December
1, 2003, the committed borrowing base was set at $68.5 million. The unused
portion of the committed borrowing base is subject to an annual commitment fee
of 0.5%. See Liquidity and Capital ResourcesCommon Stock Transactions and
Liquidity and Capital ResourcesSenior Credit Facility for explanation of
the changes in our outstanding debt balance under our senior credit facility. As of March 26, 2004, we had $29.2 million of borrowings outstanding and $39.3
million of additional borrowing capacity under our senior credit facility. Borrowings under our senior credit facility are secured by substantially all of
our oil and natural gas properties. At our option, borrowings under our senior
credit facility bear interest at a rate equal to: (i) the base rate of Société
Générale plus a margin which fluctuates from 0.5% to 1.5% depending on facility
usage or (ii) LIBOR for one, two, three or six months plus a margin which
fluctuates from 1.5% to 2.5% depending on facility usage. Interest is due
quarterly for base rate tranches or periodically as LIBOR tranches mature. The senior credit facility agreement contains various covenants and restrictive
provisions, which limit our ability to incur additional indebtedness, sell
properties, purchase or redeem our capital stock, make investments or loans,
create liens and make certain acquisitions. Our senior credit facility requires
us to maintain a current ratio (as defined) of at least 1 to 1 and an interest
coverage ratio (as defined) of at least 3.25 to 1. Should we be unable to
comply with these or other covenants, our senior lenders may be unwilling to
waive compliance or amend the covenants in the future. In such instance, our
liquidity may be adversely affected, which could in turn have an adverse impact
on our future financial position and results of operations. If we should fail
to perform our obligations under these and other covenants, the revolving
credit commitment could be terminated and any outstanding borrowings under the
facility could be declared immediately due and payable. Our current ratio at December 31, 2003 and interest
coverage ratio for the twelve-month period ending December 31, 2003, were 2.0
to 1 and 8.2 to 1, respectively. Senior Subordinated Notes As of December 31, 2003, we had $20 million of senior subordinated notes
outstanding. The terms of the senior subordinated notes were amended in March
2003 in order to have the covenants and other features of the notes mirror
those of the new senior credit facility put in place at the same time. See
Senior Credit Facility. The terms of the senior subordinated notes were
amended again in December 2003 to reduce the outstanding balance of the notes
to $20 million, reduce the interest rate and extend the maturity of the notes
from October 2005 until March 2009. Prior to the December 2003 amendment, the
senior subordinated notes bore interest at 10.75% per annum, were redeemable at
our option for face value at any time and had no principal repayment
obligations. As a consequence of the December 2003 amendment, the 10.75% fixed
rate coupon was converted to a floating rate coupon. Simultaneous with the
completion of the amendment, we entered into an interest rate swap contract to
fix the coupon at 8.76% through the new maturity date. Interest on the senior
subordinated notes is payable quarterly in arrears on the first business day
following the last day of each quarter ended March, June, September and
December. See Liquidity and Capital ResourcesSenior Subordinated Notes for
explanation of the changes in our outstanding senior subordinated notes
balance. The senior subordinated notes are secured obligations ranking junior to our
senior credit facility and have covenants similar to the senior credit
facility. As part of the December 2003 amendment, one additional covenant was
added. We are required to maintain a ratio of risked net present
value (as
defined) discounted at 9% to total debt of 1.5 to 1. 29




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##### Table of Contents



Mandatorily Redeemable Preferred Stock As of December 31, 2003, we had $8.8 million in mandatorily redeemable Series A
preferred stock outstanding, which is held by merchant banking funds managed by
affiliates of CSFB Private Equity. At our option, the dividends on our Series
A preferred stock may be paid in cash at a rate of 6% per annum or paid in kind
through the issuance of additional shares of preferred stock in lieu of cash at
a rate of 8% per annum. Our option to pay dividends in kind expires
in October
2005. To date, we have satisfied all of the dividend payments with issuance of
additional shares of Series A preferred stock. The Series A preferred stock
matures in November 2010 and is redeemable at our option at 100% or 101% of the
stated value per share (depending upon certain conditions) at anytime prior to
maturity. Our preferred stock balance outstanding at December 31, 2003, represents the
balance of preferred stock that remained outstanding after CSFB Private Equity
exercised its warrants to purchase our common stock in November and December of
this year. Over the past four years we have issued mandatorily redeemable
preferred stock to CSFB Private Equity on three different occasions. The first
issuance was in November 2000 ($20 million Series A  Tranche 1), the second
issuance was in March 2001($10 million Series A  Tranche 2) and the third
issuance was in December 2002 ($10 million Series B). In connection with each issuance of mandatorily redeemable preferred stock, we
issued to CSFB Private Equity warrants to purchase shares of our common stock.
To exercise the warrants, CSFB Private Equity had the option to use either cash
or shares of our mandatorily redeemable preferred stock with an aggregate value
equal to the exercise price. In November 2000, in connection with the Series A
 Tranche 1 we issued CSFB Private Equity warrants to purchase 6,666,667 shares
of our common stock at an exercise price of $3.00. In March 2001, in
connection with the Series A  Tranche 2 we issued CSFB Private Equity warrants
to purchase 2,105,263 shares of our common stock at an exercise price of $4.75.
The exercise price on the warrants issued in March 2001 was later reset to
$4.35 in connection with the issuance of the December 2002 Series B preferred
stock and warrant offering. In December 2002, in connection with the Series B
we issued CSFB Private Equity warrants to purchase 2,298,850 shares of our
common stock at an exercise price of $4.35 per share. As part of each warrant
agreement, we had the option to require CSFB Private Equity to exercise the
warrants if the price of our common stock met certain thresholds over a certain
period of time. In the event our stock price closed above $5.00 per share each
day for 60 consecutive days, we could require CSFB Private Equity to exercise
the warrants to purchase 6,666,667 shares of our common stock at an exercise
price of $3.00. If our stock price averaged at least $6.525 (150% of the
exercise price of the warrants) over 60 consecutive trading days, then we could
require CSFB Private Equity to exercise the warrants to purchase 2,105,263
shares of our common stock at an exercise price of $4.35 and the warrants to
purchase 2,298,850 shares of our common stock at an exercise price of $4.35. In November 2003, our stock price met the threshold, which enabled us to
require CSFB Private Equity to exercise the warrants to purchase 6,666,667
shares of our common stock at an exercise price of $3.00. In November 2003,
our average stock price met the threshold, which enabled us to require CSFB
Private Equity to exercise the warrants to purchase 2,105,263 shares of our
common stock at an exercise price of $4.35 and the warrants to purchase
2,298,850 shares of our common stock at an exercise price of $4.35. In all
three cases, we required CSFB Private Equity to exercise the warrants. The
combined exercise price of the warrants was $39.2 million and CSFB Private
Equity elected to use 1,457,900 shares of Series A preferred stock and 500,002
shares of Series B preferred stock to pay for the exercise of the warrants. In
addition, pursuant to the terms of the Series B preferred stock we paid CSFB
Private Equity approximately $704,000 to redeem the shares of Series B
preferred stock that remained outstanding after the exercise. Our outstanding balance of mandatorily redeemable preferred stock at December
31, 2003, consisted of the Series A shares that remained outstanding after the
exercise and an additional 24,738 Series A shares issued to satisfy pay in kind
dividends for the fourth quarter of 2003. 30




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##### Table of Contents



Capital Expenditures The timing of most of our capital expenditures is discretionary because we have
no material long-term capital expenditure commitments. Consequently, we have a
significant degree of flexibility to adjust the level of our capital
expenditures as circumstances warrant. Our capital expenditures for the past
three years are as follows: Year Ended December 31,2003
    
    
    2002
    
    
    2001(dollars in thousands)Drilling
    
    $
    35,106
    
    
    $
    19,800
    
    
    $
    27,209Land, geological and geophysical
    
    
    6,867
    
    
    
    3,751
    
    
    
    2,750Capitalized general and administrative expenses and
interest
    
    
    6,081
    
    
    
    5,657
    
    
    
    6,050Proceeds from participants and sales
    
    
    (1,220
    )
    
    
    (1,524
    )
    
    
    (397
    )Net capital expenditures on oil and gas activities
    
    $
    46,834
    
    
    
    27,684
    
    
    
    35,612Other property and equipment
    
    
    349
    
    
    
    249
    
    
    
    241Total net capital expenditures
    
    $
    47,183
    
    
    $
    27,933
    
    
    $
    35,853Amounts spent to develop our proved undeveloped reserves
    
    $
    11,399
    
    
    $
    9,983
    
    
    $
    8,175
 Off Balance Sheet Arrangements We currently
have operating leases, which are considered off balance sheet
arrangements. See Contractual Obligations for future
obligations associated with our operating leases. We do not currently have any
other off balance sheet arrangements or other such unrecorded
obligations, and
we have not guaranteed the debt of any other party. Results of Operations Comparison of the twelve-month periods ended December 31, 2003, 2002 and 2001 Production.Our net equivalent production volumes for 2003 were 10.7 Bcfe (29.7
MMcfe/d) compared to 10.0 Bcfe (27.8 MMcfe/d) in 2002 and 9.6 Bcfe (26.6
MMcfe/d) in 2001. The increase in production volume was due to production
growth from wells that were drilled and completed during the periods. New
production from these wells was partially offset by the natural decline of
existing production. Natural gas represented 60%, 58% and 71% of our total
production in 2003, 2002 and 2001, respectively. Year Ended December 31,2003
    
    
    % Change
    
    
    2002
    
    
    % Change
    
    
    2001Net Production Volumes:Natural gas (MMcf)
    
    
    6,356
    
    
    
    10
    %
    
    
    5,791
    
    
    
    (14
    %)
    
    
    6,766Oil (MBbls)
    
    
    720
    
    
    
    3
    %
    
    
    701
    
    
    
    50
    %
    
    
    468Natural gas equivalent (MMcfe)
    
    
    10,674
    
    
    
    7
    %
    
    
    9,996
    
    
    
    4
    %
    
    
    9,573
 For 2003 compared to 2002, the change in our production volumes was due to the
following:  
    
    Production from our Gulf Coast province for 2003 increased 24% when
compared to production from that province in 2002. Gulf Coast
production represented 61% of our total production in 2003 versus 53%
in 2002. Natural gas represented approximately 60% of the total
production from the Gulf Coast in 2003 compared to 61% in 2002.
    
    Production from our Anadarko Basin province for 2003 decreased 6% when
compared to production from that province in 2002. Anadarko Basin
production represented 23% of our total production in 2003 versus 26%
in 2002. Natural gas represented approximately 90% of the total
production from the Anadarko Basin in 2003 and 2002.
    
    Production from our West Texas province for 2003 decreased 21% when
compared to production from that province in 2002. West Texas
production represented 16% of our total production versus 21% in 2002.
Production from our West Texas province is primarily oil. Oil
represented approximately 85% of the total production from our West
Texas province in 2003 versus 88% in 2002. 31




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##### Table of Contents



For 2002 compared to 2001, the change in our production volumes was due to the
following:  
    
    Production from our Gulf Coast province for 2002 increased 37% when
compared to production from that province in 2001. Gulf Coast
production represented 53% of our total production in 2002 versus 41%
in 2001. Natural gas represented approximately 61% of the total
production from the Gulf Coast in 2002 compared to 83% in 2001.
    
    Production from our Anadarko Basin province for 2002 decreased 30%
when compared to production from that province in 2001. Anadarko
Basin production represented 26% of our total production in 2002
versus 38% in 2001. Natural gas represented approximately 90% of the
total production from the Anadarko Basin in 2002 versus 91% in 2002.
    
    Production from our West Texas province for 2002 decreased 3% when
compared to production from that province in 2001. West Texas
production represented 21% of our total production in 2002 and 2001.
Production from our West Texas province is primarily oil. Oil
represented approximately 88% of the total production from our West
Texas province in 2002 and 2001. Revenue from the sale of oil and natural gas.Revenues from the sale of oil
and natural gas that we report are based on the market price received for our
commodities adjusted by marketing charges and the results from the settlement
of our derivative commodity contracts that qualify for hedge accounting
treatment under SFAS 133. We utilize commodity swap, collar and floor contracts to (i) reduce the effect
of price volatility on the commodities that we produce and sell, (ii) reduce
commodity price risk and (iii) provide a base level of cash flow in order to
assure we can execute at least a portion of our capital spending plans. See
Item 7A. Quantitative and Qualitative Disclosures About Market
RiskQualitative DisclosuresCommodity Price Risk for a description of
derivative commodity contracts. The effective portions of changes in the fair values of our derivative
commodity contracts that qualify for hedge accounting treatment under SFAS 133
are deferred as increases or decreases to stockholders equity until the
underlying contract is settled. Consequentially, changes in the effective
portions of our derivative commodity contracts that qualify for hedge
accounting treatment under SFAS 133 add volatility to our reported
stockholders equity until the contract is settled or is terminated. See Notes
to the Consolidated Financial StatementsNote 2. The gain or loss related to the ineffective portion of changes in the fair
market value of our derivative commodity contracts that qualify for hedge
accounting treatment under SFAS 133 is recognized in other income (expense). The gain or loss related to the settlement and changes in the fair values of
our derivative commodity contracts that do not qualify for hedge accounting
treatment under SFAS 133 are recognized in other income (expense). All of our open derivative commodity contracts at December 31, 2003, qualified
for hedge accounting treatment under SFAS 133.
See Item 7A. Quantitative and Qualitative Disclosures About Market
RiskQualitative DisclosuresCommodity Price Risk for our open derivative
commodity contracts at December 31, 2003. 32




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##### Table of Contents



The table below shows revenue that we have realized from the sale of oil and
natural gas over the past three years. Year Ended December 31,2003
    
    
    % Change
    
    
    2002
    
    
    % Change
    
    
    2001(dollars in thousands, except per unit measurements)Revenue from the sale of oil and natural gas:Oil sales
    
    $
    22,157
    
    
    
    26
    %
    
    $
    17,644
    
    
    
    55
    %
    
    $
    11,405Gain/(loss) due to hedging
    
    
    (1,885
    )
    
    
    66
    %
    
    
    (1,135
    )
    
    
    642
    %
    
    
    (153
    )Total revenue from the sale of oil
    
    $
    20,272
    
    
    
    23
    %
    
    $
    16,509
    
    
    
    47
    %
    
    $
    11,252Natural gas sales
    
    $
    36,080
    
    
    
    87
    %
    
    $
    19,303
    
    
    
    (34
    %)
    
    $
    29,042Gain/(loss) due to hedging
    
    
    (4,807
    )
    
    
    575
    %
    
    
    (712
    )
    
    
    (91
    %)
    
    
    (8,001
    )Total revenue from the sale of natural gas
    
    $
    31,273
    
    
    
    68
    %
    
    $
    18,591
    
    
    
    (12
    %)
    
    $
    21,041Oil and natural gas sales
    
    $
    58,237
    
    
    
    58
    %
    
    $
    36,947
    
    
    
    (9
    %)
    
    $
    40,447Gain/(loss) due to hedging
    
    
    (6,692
    )
    
    
    262
    %
    
    
    (1,847
    )
    
    
    (77
    %)
    
    
    (8,154
    )Total revenue from the sale of oil and
natural gas
    
    $
    51,545
    
    
    
    47
    %
    
    $
    35,100
    
    
    
    9
    %
    
    $
    32,293Average prices:Oil ($  per Bbl)Oil
    
    $
    30.79
    
    
    
    22
    %
    
    $
    25.17
    
    
    
    3
    %
    
    $
    24.38Gain/(loss) due to hedging
    
    
    (2.62
    )
    
    
    62
    %
    
    
    (1.62
    )
    
    
    391
    %
    
    
    (0.33
    )Oil realized price
    
    $
    28.17
    
    
    
    20
    %
    
    $
    23.55
    
    
    
    (2
    %)
    
    $
    24.05Natural gas ($  per Mcf)Natural gas sales price
    
    $
    5.68
    
    
    
    71
    %
    
    $
    3.33
    
    
    
    (22
    %)
    
    $
    4.29Gain/(loss) due to hedging
    
    
    (0.76
    )
    
    
    533
    %
    
    
    (0.12
    )
    
    
    (90
    %)
    
    
    (1.18
    )Natural gas realized price
    
    $
    4.92
    
    
    
    53
    %
    
    $
    3.21
    
    
    
    3
    %
    
    $
    3.11Natural gas equivalent ($  per Mcfe)Natural gas equivalent sale price
    
    $
    5.46
    
    
    
    48
    %
    
    $
    3.70
    
    
    
    (13
    %)
    
    $
    4.23Gain/(loss) due to hedging
    
    
    (0.63
    )
    
    
    232
    %
    
    
    (0.19
    )
    
    
    (78
    %)
    
    
    (0.86
    )Natural gas equivalent realized price
    
    $
    4.83
    
    
    
    38
    %
    
    $
    3.51
    
    
    
    4
    %
    
    $
    3.37
 Our total revenue from the sale of oil and natural gas in 2003 was 47% higher
than total revenue from the sale of oil and natural gas in 2002. The change in
our total revenue from the sale of oil and natural gas from 2002 to 2003 is due
to the following:  
    
    Approximately $19 million of the increase in oil and natural gas sales was due to a $1.76 Mcfe increase in the sales price
that we received for oil and natural gas.
    
    The remaining $2.3 million of the increase in oil and natural gas sales was due to an increase in our production volumes.
    
    The increases in total revenue from the sale of oil and natural gas due to higher prices and increased production volumes
were partially offset by a 262% increase in losses due to the cash settlement of derivative commodity contracts. Our total revenue from the sale of oil and natural gas in 2002 was 9% lower
than total revenue from the sale of oil and natural gas in 2001. The change in
our total revenue from the sale of oil and natural gas from 2002 to 2001 is due
to the following:  
    
    Approximately $5 million of the decrease in oil and natural gas sales
was due to a $0.53 per Mcfe decline in the average sales price that we
received for oil and natural gas.
    
    The decrease in oil and natural gas sales due to a decline in the
average sales price that we received for oil and natural gas was
partially offset by a $1.5 million increase in oil and natural gas
sales related to an increase in oil and natural gas production.
    
    The decrease in total revenue from oil and natural gas sales due to a
decline in the average sales price that we received for oil and
natural gas was partially offset by a 77% decrease in losses due to
the cash settlement of derivative commodity contracts. 33




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##### Table of Contents



The following table shows the type of derivative commodity contracts, the
volumes, the weighted average NYMEX reference price for those volumes, and the
associated gain /(loss) upon settlement of those hedges for 2003, 2002 and
2001. Year Ended December 31,2003
    
    
    2002
    
    
    2001Oil swapsVolumes (Bbls)
    
    
    225,525
    
    
    
    126,500
    
    
    
    Average price ($  per Bbl)
    
    $
    24.51
    
    
    $
    25.96
    
    
    $
    Gain / (loss) (dollars in thousands)
    
    $
    (1,488
    )
    
    $
    (284
    )
    
    $
    Oil collarsVolumes (Bbls)
    
    
    45,250
    
    
    
    204,500
    
    
    
    109,200Average floor price ($  per Bbl)
    
    $
    18.00
    
    
    $
    18.00
    
    
    $
    17.36Average ceiling price ($  per Bbl)
    
    $
    22.56
    
    
    $
    22.36
    
    
    $
    26.15Gain / (loss) (dollars in thousands)
    
    $
    (397
    )
    
    $
    (851
    )
    
    $
    (153
    )Natural gas swapsVolumes (MMbtu)
    
    
    2,663,500
    
    
    
    3,358,500
    
    
    
    1,800,000Average price ($  per MMbtu)
    
    $
    3.81
    
    
    $
    3.13
    
    
    $
    2.09Gain / (loss) (dollars in thousands)
    
    $
    (4,807
    )
    
    $
    (712
    )
    
    $
    (8,006
    )Natural gas floorsVolumes (MMbtu)
    
    
    1,070,000
    
    
    
    
    
    
    
    765,000Average floor price ($  per MMbtu)
    
    $
    4.50
    
    
    $
    
    
    
    $
    1.80Gain / (loss) (dollars in thousands)
    
    $
    
    
    
    $
    
    
    
    $
    5
 Other revenue.Other revenue relates to fees that we charge other parties who
use our two gas gathering systems to move their production from the wellhead to
third party gas pipeline systems. These gathering systems are owned by us and
located in the Texas Gulf Coast. One of the gathering systems connects to a
single well and the other connects two wells. Other revenue for 2003 was
$132,000 compared to $76,000 in 2002 and $255,000 in 2001. Production costs.Production costs include lease operating expenses and
production taxes. Year Ended December 31,2003
    
    
    % Change
    
    
    2002
    
    
    % Change
    
    
    2001(dollars in thousands, except per unit measurements)Production cost:Lease operating expenses,
excluding ad valorem taxes
    
    $
    4,543
    
    
    
    44
    %
    
    $
    3,148
    
    
    
    4
    %
    
    $
    3,015Ad valorem taxes
    
    
    657
    
    
    
    8
    %
    
    
    611
    
    
    
    30
    %
    
    
    471Total lease operating expenses
    
    $
    5,200
    
    
    
    38
    %
    
    $
    3,759
    
    
    
    8
    %
    
    $
    3,486Production taxes
    
    
    2,477
    
    
    
    25
    %
    
    
    1,977
    
    
    
    31
    %
    
    
    1,511Total production expenses
    
    $
    7,677
    
    
    
    34
    %
    
    $
    5,736
    
    
    
    15
    %
    
    $
    4,997Production cost ($  per Mcfe):Lease operating expenses,
excluding ad valorem taxes
    
    $
    0.43
    
    
    
    34
    %
    
    $
    0.32
    
    
    
    0
    %
    
    $
    0.32Ad valorem taxes
    
    
    0.06
    
    
    
    0
    %
    
    
    0.06
    
    
    
    20
    %
    
    
    0.05Total lease operating expenses
    
    $
    0.49
    
    
    
    29
    %
    
    $
    0.38
    
    
    
    3
    %
    
    $
    0.37Production taxes
    
    
    0.23
    
    
    
    15
    %
    
    
    0.20
    
    
    
    25
    %
    
    
    0.16Total production expenses
    
    $
    0.72
    
    
    
    24
    %
    
    $
    0.58
    
    
    
    9
    %
    
    $
    0.53
 Lease
operating expenses: Lease operating expenses are generally comprised of several components which
include the cost of labor and supervision to operate the wells and related
equipment; repairs and maintenance; related materials, supplies, fuel, and
supplies utilized in operating the wells and related equipment and facilities;
insurance applicable to wells and related facilities and equipment, workover
cost and ad valorem taxes. Lease operating expenses are driven in part by the
type of commodity produced, the level of workover activity and the geographical
location of the properties. Oil is inherently more expensive to produce than
natural gas. 34




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##### Table of Contents



Local taxing authorities such as school districts, cities, and counties or
boroughs generally impose the ad valorem taxes we pay. The amount of the tax is
based on the value of the property assessed or determined by the taxing
authority on an annual basis, and a percent of value. When oil and natural gas
commodity prices rise, the value of our underlying property interests increase.
This results in higher ad valorem taxes. For 2003 compared to 2002, approximately 58% of the increase in total lease
operating expenses was due to an increase in workover activity, while 39% of
the increase was related to an increase in operating and maintenance expense
and 3% was related to an increase in ad valorem taxes. On a per unit basis, our lease operating expenses for 2003 were $0.49 per Mcfe
compared to $0.38 in 2002. The $0.11 increase in lease operating expense was
primarily due to the following:  
    
    An increase in workover activity represented $0.07 of the increase in
lease operating expenses, with two workovers performed on two wells
accounting for 100% of this increase.
    
    The remaining $0.04 of the increase in lease operating expenses was
due to increases in overhead fees, insurance, compressor rental and
maintenance, saltwater disposal cost, cost for electricity, fuel and
power and miscellaneous lease operating expenses. These increases
were partly offset by decreases in contract service and labor
expenses, lease and well abandonment expenses, lease maintenance
expenses and surface equipment repair expenses. For 2002 compared to 2001, approximately 51% of the increase in total lease
operating expenses was due to an increase in ad valorem taxes and 49% of the
increase was due to an increase in workover activity, which was partially
offset by a decrease in operating and maintenance expenses. The increase in ad
valorem taxes was due to an increase in 2002 property valuation because of
higher average commodity prices during 2001. On a per unit basis, our lease operating expenses for 2002 were $0.38 per Mcfe
compared to $0.37 in 2001.  
    
    An increase in expenses related to workover activity resulted in a $0.02 increase in lease operating expenses.
    
    An increase in ad valorem taxes resulted in a $0.01 increase in lease operating expenses.
    
    These increases were offset by decreases in well service and repair expenses. Production
taxes: In the U.S. there are a variety of state and federal taxes levied on the
production of oil and natural gas. These are commonly grouped together and
referred to as production taxes. The majority of our production tax expense is
based on a percent of gross value at the well at the time the production is
sold or removed from the lease. As a result, our production tax expense
increases with increases in crude oil and natural gas commodity prices. Historically, taxing authorities have occasionally encouraged oil and gas
industry to explore for new oil and natural gas reserves, or develop high cost
reserves through reduced tax rates or credits. These incentives have been
narrow in scope and short-lived. A small number of our wells currently qualify
for reduced production taxes because they are discoveries based on the use of
3-D seismic or high cost wells. For 2003 compared to 2002, the increase in production taxes was due to an
increase in the sales prices that we received for both oil and natural gas.
The increase in production taxes was offset by a credit related to the
settlement of a portion of our gas imbalance. Our effective production tax
rate in 2003 was 4.3% of pre-hedge oil and natural gas sales revenue, compared
to 5.4% in 2002. For 2002 compared to 2001, the increase in production taxes was primarily due
to a reduction in the number of wells that qualify for severance tax refunds in
2002. Our effective production tax rate in 2002 was 5.4% of pre-hedge oil and
natural gas sales revenue, compared to 3.7% in 2001. 35




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##### Table of Contents



General and administrative expenses.We capitalize a portion of our general
and administrative costs. The costs capitalized represent the cost of technical
employees, who work directly on capital projects. An engineer designing a well
is an example of a technical employee working on a capital project. The cost
of a technical employee includes associated technical organization costs such
as supervision, telephone and postage. Year Ended December 31,2003
    
    
    % Change
    
    
    2002
    
    
    % Change
    
    
    2001(dollars in thousands, except per unit measurements)General and administrative expenses
    
    $
    4,500
    
    
    
    (9
    %)
    
    $
    4,971
    
    
    
    37
    %
    
    $
    3,638General and administrative expenses
($  per Mcfe)
    
    $
    0.42
    
    
    
    (16
    %)
    
    $
    0.50
    
    
    
    32
    %
    
    $
    0.38
 For 2003 compared to 2002, our general and administrative expenses decreased by
$471,000. General and administrative expenses for 2002 included a non-cash
charge for compensation expense of $596,000 related to vesting of options by an
officer who left the company. Excluding this non-cash charge, our general and
administrative expenses for 2003 increased by $125,000. The changes in general
and administrative expenses for 2003 were primarily due to the following:  
    
    An increase in payroll and employee benefit expenses represented 55%
of the total increase in general and administrative expenses. The
increase in payroll and benefit expenses was primarily related to an
increase incentive compensation expense, an increase in employee
medical and life insurance cost and increases in salaries and wages.
    
    An increase in director fees and financial reporting expenses
represented 42% of the total increase in general and administrative
expenses. These increases were primarily related to additional cost
associated with the implementation of compliance with the
Sarbanes-Oxley Act of 2002.
    
    The increase in payroll and employee benefit expenses was partially
offset by an increase in amounts charged to joint ventures to cover
the costs of managing these joint operations. On a per unit basis, our general and administrative expenses for 2003 were
$0.42 per Mcfe compared to $0.50 in 2002. A charge for non-cash
compensation expense accounted for $0.06 of our 2002 general and administrative
expense. For 2002 compared to 2001, our general and administrative expenses increased by
$1.3 million. The changes in general and administrative expenses for 2002 were
primarily due to the following:  
    
    A charge for non-cash compensation expense of $596,000 related to
vesting of options by an officer who left the company accounted for
45% of the total increase in general and administrative expenses.
    
    Increases in payroll and benefit expenses represented approximately
20% of the total increase in general and administrative expenses. The
increase in payroll and benefit expenses was due to an increase in
relocation bonuses, an increase in the cost of employee medical and
life insurance and increased salaries.
    
    An increase in other office expenses accounted for 12% of the
increase, an increase in office rent accounted for 6% of the increase
and an increase in corporate insurance accounted for approximately 4%
of the increase. Our general and administrative expenses on a per unit basis for 2002 were $0.50
per Mcfe compared to $0.38 during 2001. The charge for non-cash compensation
expense accounted for $0.06 of our per unit general and administrative expense
in 2002. Depletion of oil and natural gas properties.Our full-cost depletion expense
is driven by many factors including certain costs spent in the exploration and
development of producing reserves, production levels, and estimates of proved
reserve quantities and future developmental costs at the end of the year. Year Ended December 31,2003
    
    
    % Change
    
    
    2002
    
    
    % Change
    
    
    2001(dollars in thousands, except per unit measurements)Depletion of oil and natural gas properties.
    
    $
    16,972
    
    
    
    16
    %
    
    $
    14,594
    
    
    
    10
    %
    
    $
    13,211Depletion of oil and natural gas properties
per Mcfe
    
    $
    1.59
    
    
    
    9
    %
    
    $
    1.46
    
    
    
    3
    %
    
    $
    1.38
 For 2003 compared to 2002, a $0.13 increase in our depletion rate accounted for
approximately $1.4 million of the increase in our total depletion expense and
increased production volumes accounted for approximately $1 million of the
increase. The increase in our 36




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##### Table of Contents



depletion rate was due to an increase in our oil and natural gas finding and
development costs incurred in 2003 and an increase in future development costs
associated with our year-end 2003 reserves. For 2002 compared to 2001, a $0.08 increase in our depletion rate accounted for
$800,000 of the change in our total depletion expense and higher production
volumes accounted for $584,000 of the change. This increase in depletion rate
was due to an increase in the future development costs associated with our
Floyd Fault Block Field discovery. Net interest expense.We capitalize interest expense on borrowings associated
with major capital projects prior to their completion. Capitalized interest is
added to the cost of the underlying assets and is amortized over the lives of
the assets. Year Ended December 31,%
    
    
    
    
    
    %2003
    
    
    Change
    
    
    2002
    
    
    Change
    
    
    2001(dollars in thousands)Interest on senior credit facility
    
    $
    1,674
    
    
    
    (54
    %)
    
    $
    3,636
    
    
    
    (33
    %)
    
    $
    5,400Interest on senior subordinated notes (a)
    
    
    2,369
    
    
    
    6
    %
    
    
    2,243
    
    
    
    33
    %
    
    
    1,681Commitment fees
    
    
    147
    
    
    
    4,800
    %
    
    
    3
    
    
    
    (90
    %)
    
    
    29Dividend on mandatorily redeemable
preferred stock
    
    
    340
    
    
    
    0
    %
    
    
    
    
    
    
    0
    %
    
    
    Amortization of deferred loan and debt issuance cost
    
    
    1,053
    
    
    
    (11
    %)
    
    
    1,190
    
    
    
    (13
    %)
    
    
    1,372Other general interest expense
    
    
    50
    
    
    
    14
    %
    
    
    44
    
    
    
    (6
    %)
    
    
    47Capitalized interest expense
    
    
    (818
    )
    
    
    (7
    %)
    
    
    (878
    )
    
    
    (52
    %)
    
    
    (1,848
    )Net interest expense
    
    $
    4,815
    
    
    
    (23
    %)
    
    $
    6,238
    
    
    
    (7
    %)
    
    $
    6,681Weighted average debt outstanding
    
    $
    71,392
    
    
    
    (25
    %)
    
    $
    95,562
    
    
    
    5
    %
    
    $
    90,646Average interest rate on outstanding indebtedness (b)
    
    
    6.3
    %
    
    
    
    
    
    
    6.2
    %
    
    
    
    
    
    
    7.8
    %(a)  Interest expense on our senior subordinated
notes that was paid in kind through the issuance of
additional debt in lieu of cash. Our option to pay
interest in kind on our senior subordinated notes
expired in October 2003.
    
    $
    1,196
    
    
    
    11
    %
    
    $
    1,076
    
    
    
    49
    %
    
    $
    721
  (b)
    
    Calculated as the sum of the interest expense on our outstanding indebtedness,
commitment fees and the dividend on our mandatorily redeemable preferred stock divided
by the weighted average debt and preferred stock outstanding for the period. For 2003 compared to 2002, the following were the primary reasons for the
changes in our interest expense:  
    
    A decrease in the amount of interest that we paid on our senior credit
facility. This decrease in interest expense on our senior credit was due
to the following.  
    
    Our weighted average outstanding debt under our senior credit
facility during 2003 was $44.9 million, compared to $74.7 million. See
Liquidity and Capital ResourcesSenior Credit Facility for changes in
the amounts that we have outstanding under our senior credit facility.
    
    A decrease in the average interest rate that we owe on outstanding
balances under our senior credit facility. In March 2003 we amended our
senior credit facility and lowered the interest rate that we owe on
borrowings outstanding under our senior credit facility. See Capital
CommitmentsContractual Obligations and Item 7A Quantitative and
Qualitative Disclosures About Market RiskQuantitative
DisclosuresInterest Rate Risk for future interest expense and the
sensitivity of interest expense on senior credit facility to changes in
short-term interest rates.  
    
    An increase in the amount of interest that we paid on our senior
subordinated notes due to an increase in the weighted average senior
subordinated notes outstanding from $20.9 in 2002 to $22.2 in 2003.
Our outstanding senior subordinated notes balance increased during
2003 because a portion of the interest expense was paid in kind
through the issuance of additional debt in lieu of cash. In December
2003, we decreased the amount of senior subordinated notes outstanding
and lowered the interest rate on our senior subordinated notes. See
Capital CommitmentsSenior Subordinated Notes for additional
discussion on the amendment to our senior subordinated notes and
Liquidity and Capital ResourcesSenior Subordinated Notes for
additional information about the changes in our senior subordinated
notes outstanding.
    
    Upon our adoption of SFAS 150 in July 2003, we reclassified
approximately $8 million of our then outstanding mandatorily
redeemable Series A and Series B preferred stock, which has no equity
conversion features and must be settled with our assets, to long-term
debt. As part of this reclassification, the dividends that have been
paid on the reclassified amount since July 2003 have been reported as
interest expense. See Critical Accounting PoliciesNew Accounting Pronouncements. 37




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##### Table of Contents



For 2002 compared to 2001, the change in net interest expense was primarily due
to a lower average interest rate on outstanding indebtedness during 2002 and to
a lesser extent on a decrease in the amount of deferred loan fees amortized.
The change in the average interest rate on our outstanding borrowings was due
to a decrease in LIBOR, which is used to determine the interest rate on
borrowings outstanding under our senior credit facility. The average interest
rate on borrowings outstanding under our senior credit facility during 2002 was
4.9% compared to 7.2% in 2001. At December 31, 2002, the interest rate on
borrowings outstanding under our senior credit facility was 4.5%. Other income (expense).Other income (expense) primarily includes non-cash
gains (losses) resulting from the change in fair market value of oil and gas
derivative contracts that did not qualify as hedges, cash gains (losses) on the
settlement of these contracts and non-cash gains (losses) related to charges
for the ineffective portions of cash flow hedges. Other income (expense) included: Year Ended December 31,2003
    
    
    2002
    
    
    2001(dollars in thousands)Non-cash gain (loss) due to change in fair
market value of derivative contracts that did
not qualify as hedges
    
    $
    
    
    
    $
    384
    
    
    $
    9,666Non-cash loss for ineffective portion of hedges
    
    
    (455
    )
    
    
    (122
    )
    
    
    Cash gain (loss) on settlement of derivative
contracts that did not qualify as hedges
    
    
    
    
    
    
    (559
    )
    
    
    (1,492
    )Gain (loss) on investments
    
    
    
    
    
    
    21
    
    
    
    (94
    )Other
    
    
    (146
    )
    
    
    (34
    )
    
    
    Total
    
    $
    (601
    )
    
    $
    (310
    )
    
    $
    8,080
 The following table shows the volumes and the weighted average NYMEX reference
price for those volumes for our derivative commodity contracts that did not
qualify for hedge accounting treatment under SFAS 133 in 2003, 2002 and 2001: Year Ended December 31,2003
    
    
    2002
    
    
    2001Natural gas capsVolumes (MMbtu)
    
    
    
    
    
    
    1,810,000
    
    
    
    2,450,000Average ceiling price ($  per MMbtu)
    
    $
    
    
    
    $
    2.63
    
    
    $
    2.55
 Debt conversion expense.Debt conversion expense of $630,000 in 2002
represents the costs and fees we incurred to execute the conversion of $10
million of our senior debt to common stock. Our total outstanding indebtedness
at December 31, 2002 was $81.8 million, compared to $91.7 million at December
31, 2001. There were no similar expenses in prior periods. Income tax benefit.Realization of deferred tax assets associated with (i)
NOLs, and (ii) existing temporary differences between book and taxable income
is dependent upon generating sufficient taxable income of the appropriate
character (i.e., ordinary income or capital gain) within the carryforward
period available under tax law. Prior to the current year, management believed
that it was more likely than not that its deferred tax assets would not be
realized and, therefore, reflected a comparable valuation allowance. However,
as a result mainly of the increased level of capital expenditures resulting
from the September 2003 equity offering, management now believes that Brigham
should (i) begin to utilize NOLs, and (ii) have reversals of existing
temporary differences between book and taxable income sufficient to result in
future deferred tax liabilities. Therefore, we have recognized a deferred
tax asset at December 31, 2003, of $2.2 million, consisting of a $1.6 million
income tax benefit and a $0.6 million tax effect of unrealized hedging losses.
Also at December 31, 2003, management believes it is more likely than not that
capital loss carryforwards of approximately $1.8 million may expire unused and,
accordingly, has established a valuation allowance of $0.6 million. Dividends and accretion of mandatorily redeemable preferred stock.We are
required to pay dividends on our Series A and Series B preferred stock. At our
option, these dividends may be paid in cash at a rate of 6% per annum or paid
in kind through the issuance of additional shares of preferred stock in lieu of
cash at a rate of 8% per annum. We elected to pay dividends in kind in each
quarter of 2003, 2002 and 2001. 38




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##### Table of Contents



Upon our adoption of SFAS 150 in July 2003, we reclassified approximately $8
million of our then outstanding mandatorily redeemable Series A and Series B
preferred stock that must be settled with our assets to long-term debt. As part
of the reclassification, the dividend that has been paid on the reclassified
amount since July 2003 has been reported as interest expense. See  Critical Accounting Policies  New
Accounting Pronouncements. In November and December 2003, CSFB Private Equity used a portion of our
mandatorily redeemable Series A and Series B preferred stock that it held to
pay for the exercise of the associated warrants. We also redeemed the
remaining balance of Series B preferred stock that was not used to pay for the
exercise. See Capital CommitmentsMandatorily Redeemable Preferred Stock. The following table shows the effect on our balance sheet for the years ended
December 31, 2003, 2002 and 2001 of the issuance of additional shares of
preferred stock in lieu of paying cash dividends. Year Ended December 31,2003
    
    
    2002
    
    
    2001(dollars in thousands)Dividends
    
    $
    3,061
    
    
    $
    2,713
    
    
    $
    2,347Accretion of mandatorily redeemable preferred stock
    
    
    387
    
    
    
    239
    
    
    
    103Total
    
    $
    3,448
    
    
    $
    2,952
    
    
    $
    2,450Additional preferred shares issuedSeries A
    
    
    132,490
    
    
    
    134,440
    
    
    
    117,358Series B
    
    
    30,603
    
    
    
    1,226
    
    
    
    
 Liquidity and Capital Resources During 2003, we strengthened our balance sheet and enhanced our financial
flexibility through the completion of the equity offering and new senior credit
facility, as well as by continuing to build upon the solid financial
performances of recent years. Cash will be required to fund capital
expenditures for the exploration and development of oil and natural gas
properties necessary to offset the inherent declines in production and proven
reserves typical in an extractive industry like ours. Future success in growing
reserves and production will be highly dependent on our access to cost
effective capital resources and our success in economically finding and
producing additional reserves. We believe that cash on hand, net cash provided
by operating activities, and the unused committed borrowing capacity under our
senior credit facility will be adequate to satisfy future financial obligations
and liquidity. In the current environment of higher commodity prices, there may be increased
demand for drilling equipment and services, leases and economically attractive
prospects, which then may result in less availability and higher costs to us
for those resources. Also, we may face additional competition from both
domestic and international sources of supply, which may exert a downward
pressure on the prices we ultimately receive for our products. In addition, a significant known trend expected by our management to have an
effect on our liquidity is our plan to accelerate our drilling activities in
2004 relative to recent prior years. See Item 2. Properties, Overview and
"2004 Outlook for additional discussion about our 2004 capital expenditure
program. Net Cash Provided by Operating Activities Net cash provided by operating activities is a function of the prices we
receive from the sale of oil and natural gas, which are inherently volatile and
unpredictable, production, operating cost, our cost of capital and capital
spending. Our asset base, as with other extractive industries, is a depleting
one in which each Mcf of natural gas or barrel of oil produced must be replaced
or our ability to generate cash flow, and thus sustain our exploration and
development activities, will diminish. See Risk FactorsOur Future Operating
Results May Fluctuate and Significant Declines in Them Would Limit Our Ability
To Invest In Projects and Risk FactorsThe Failure To Replace Reserves In
The Future Would Adversely Affect Our Production And Cash Flows. Year Ended December 31,2003
    
    
    % Change
    
    
    2002
    
    
    % Change
    
    
    2001(dollars in thousands)Net cash flow provided by operating activities
    
    $
    41,691
    
    
    
    44
    %
    
    $
    28,973
    
    
    
    53
    %
    
    $
    18,922
 For 2003 compared to 2002, higher commodity prices combined with lower cash
interest costs were the primary reasons for the $12.7 39




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million increase in net cash provided by operating activities. The higher
commodity prices and lower cash interest costs were partially offset by an
increase in production costs. Our working capital deficit at December 31,
2003, was $14.7 million compared to a working capital deficit of $688,000 at
December 31, 2002. Working capital is the amount by which current assets exceed
current liabilities. It is normal for us to report a working capital deficit at
the end of a period. These deficits are primarily the result of accounts
payable related to lease operating expenses, exploration and development costs,
royalties payable and gas imbalances payable. Settlement of these payables will
be funded by cash flows from operations or, if necessary, by additional
borrowing under our senior credit facility.
Our gas imbalance related to the wells in Home Run Triple Crown and Floyd Fault
Block Fields was partially settled in November 2003. Due to the settlement, we
borrowed an additional $4 million under our senior credit facility. The
settlement reduced the balance of our gas imbalance payable by $11.3 million
and reduced the balance of our gas imbalance receivable by approximately $7.2
million. At December 31, 2003, current liabilities included a liability of
$2.1 million related to the fair value of hedging contracts. For 2002 compared to 2001, net cash provided by operating activities increased
$10.1 million. These changes were primarily due to an increase in our
post-hedge realized sales prices for oil and natural gas and a decrease in
interest expense related to our senior credit facility. These changes were
partially offset by increases in our lease operating expenses, production
taxes, general and administrative expenses and debt conversion cost. At
December 31, 2002 we had a working capital deficit of $688,000 compared to a
working capital surplus of $1.7 million at December 31, 2001. Cash Flows from Financing Activities Over the three year period ended December 31, 2003, we have entered into
various financing transactions with the intent of reducing our cost of capital
and increasing our liquidity so that we could fund our capital expenditures for
the exploration and development of oil and natural gas properties. Common Stock Transactions  
    
    In February 2003, we issued 248,028 unregistered shares of our common
stock to a group of institutional investors led by affiliates of two
members of our board of directors. We received no proceeds from the
exercise of the warrants as the group elected to execute a cashless
exercise of the warrants.
    
    In June 2003, we issued 408,928 and 206,982 unregistered shares of our
common stock to the Bank of Montreal and Société Générale,
respectively. We received no proceeds from the exercise of these
warrants as both parties elected to execute a cashless exercise of the
warrants. Both parties subsequently sold these shares in our
common stock sale in September 2003. We received no proceeds from
these sales.
    
    In September 2003, we issued 7,384,090 shares of common stock and
received $40 million in net proceeds. The net proceeds from the sale
will be used to accelerate the amount of capital that we can spend on
our exploration and development program and reduce our outstanding
indebtedness. Pending such use to accelerate our exploration and
development activities, the net proceeds were used to repay $40
million of the borrowings outstanding under or senior credit facility.
See Item 1. Business, Item 2. Properties and 2004 Outlook for
further discussion of future capital expenditures.
    
    In November and December 2003, we required CSFB Private Equity to
exercise warrants it held to purchase 11,070,780 shares of our common
stock. CSFB Private Equity elected to use shares of our Series A and
Series B mandatorily redeemable preferred stock that it held to pay
for the exercise prices of the warrants. We received no proceeds from
the exercise of the warrants. See Capital CommitmentsMandatorily
Redeemable Preferred Stock and Results From OperationsDividends
and Accretion of Mandatorily Redeemable Preferred Stock.
    
    We received $829,000 in net proceeds and issued 309,760 shares of
common stock related to the exercise of employee stock options during
2003.
    
    In December 2002, we issued 550,000 unregistered shares of our common
stock to Shell Capital in exchange for its warrant position, including
1,250,000 warrants associated with our senior subordinated notes
facility, and to terminate its right to convert $30 million of our
senior credit facility into 5,480,769 shares of our common stock.
Shell Capital sold the 550,000 shares in our common stock sale in
September 2003. We received no proceeds from the exchange or the
later sale of the common stock.
    
    In December 2002, CSFB Private Equity, purchased $10 million of our
senior credit facility from Shell Capital and converted it into
2,564,102 shares of our common stock at an exercise price of $3.90 per
share. We received no proceeds in this transaction.
    
    In December 2002, we issued 243,902 unregistered shares of our common
stock to a group of institutional investors led by affiliates of two
members of our board of directors. We received proceeds of $625,000
from the exercise of the warrants.
    
    We received $296,000 in net proceeds and issued 132,507 shares of our
common stock related to the exercise of employee stock options in
2002.
    
    We received $252,000 in net proceeds and issued 97,474 shares of our
common stock related to the exercise of employee stock options and
warrants in 2001. 40




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Mandatorily Redeemable Preferred Stock Transactions  
    
    In December 2002, we issued $10 million ($9.4 million net of issuance
costs) in Series B mandatorily redeemable preferred stock and warrants
to purchase our common stock. Net proceeds from the offering were
used to repay $5 million of the borrowings outstanding under our
senior credit facility, fund our exploration and development
activities and fund working capital obligations.
    
    In March 2001, we issued $10 million ($9.8 million net of issuance
costs) in Series A mandatorily redeemable preferred stock and warrants
to purchase our common stock. Net proceeds from the offering were used
to fund our exploration and development activities and working capital
obligations. Senior Credit Facility We strive to manage the borrowings outstanding under our senior credit facility
in order to maintain excess borrowing capacity. Our future outstanding balances under our senior credit facility are dependent
primarily on net cash provided by operating activities, proceeds from other
financing activities and proceeds generated from asset dispositions. Our
committed borrowing capacity under our senior credit facility is currently $80
million, with a $68.5 million borrowing base that is subject to adjustment on
the basis of the present value of estimated future net cash flows from proved
oil and gas reserves (as determined by the lenders petroleum engineer). Our
unused committed borrowing base capacity under our senior credit facility was
$49.5 million at December 31, 2003, and $39.3 million at March 26, 2004. Our
senior credit facility matures in March of 2006. See Capital
CommitmentsSenior Credit Facility. In 2003 we reduced the amount of outstanding borrowings under our senior credit
facility by $41 million. The net proceeds from the sale of common stock in
September 2003 were used to reduce borrowings outstanding under or senior
credit facility by $40 million. We also paid down an additional $4 million and
$3 million of the borrowings outstanding under our senior credit facility in
the first and second quarters of 2003. These decreases were offset by a
drawdown of $6 million in the fourth quarter of 2004 to fund a portion of the
settlement of our gas imbalance liability, fund the repayment of $3 million of
our outstanding senior subordinated notes and fund the redemption of our Series
B mandatorily redeemable preferred stock that remained outstanding after the
CSFB conversion of the majority of the Series B preferred stock and associated
warrants to common stock. We paid $1.1 million in fees related to the
amendment of our senior credit facility in March 2003. In 2002 we reduced the amount of outstanding borrowings under our senior credit
facility by $15 million. We used a portion of the net proceeds from the sale
of our Series B mandatorily redeemable preferred stock and warrants to purchase
our common stock to pay $5 million of the borrowings outstanding under our
senior credit facility. In December 2002, CSFB Private Equity purchased $10
million of our senior credit facility from Shell Capital and converted it into
2,564,102 shares of our common stock at an exercise price of $3.90 per share.
We paid $684,000 million in deferred loan fees in 2002. Senior Subordinated Notes In connection with the December 2003 amendment of our senior subordinated
notes, we reduced the outstanding balance by approximately $3 million. In 2002
and 2001, we borrowed an additional $4 million and $9 million in senior
subordinated notes. These additional borrowings were used to fund our
exploration and development activities and to fund working capital obligations.
We paid $86,000 in fees related to the amendment of our senior subordinated
credit agreement in December 2003. Other Matters Derivative Instruments Our results of operations and operating cash flow are impacted by changes in
market prices for oil and gas. We believe the use of derivative instruments,
although not free of risk, allows us to reduce our exposure to oil and natural
gas sales price fluctuations and thereby achieve a more predictable cash flow.
While the use of derivative instruments limits the downside risk of adverse
price movements, their use may also limit future revenues from favorable price
movements. Moreover, our hedging arrangements generally do not apply to all of
our production and thus provide only partial price protection against declines
in commodity prices. We expect that the amount of our hedges will vary from
time to time. See Risk FactorsOur Hedging Transactions May Not Prevent
Losses and Item 7A. Quantitative and Qualitative Disclosures About Market
Risk. 41




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Effects of Inflation and Changes in Prices Our results of operations and cash flows are affected by changing oil and
natural gas prices. If the price of oil and natural gas increases (decreases),
there could be a corresponding increase (decrease) in revenues as well as the
operating costs that we are required to bear for operations. Inflation has had
a minimal effect on us. Environmental and Other Regulatory Matters Our business is subject to certain federal, state and local laws and
regulations relating to the exploration for and the development, production and
marketing of oil and natural gas, as well as 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 we believe that we are in substantial compliance with all
applicable laws and regulations, the requirements imposed by laws and
regulations are frequently changed and subject to interpretation, and we cannot
predict the ultimate cost of compliance with these requirements or their effect
on our operations. Any suspensions, terminations or inability to meet
applicable bonding requirements could materially adversely affect our financial
condition and operations. Although significant expenditures may be required to
comply with governmental laws and regulations applicable to us, compliance has
not had a material adverse effect on our earnings or competitive position.
Future regulations may add to the cost of, or significantly limit, drilling
activity. See Risk FactorsWe Are Subject To Various Governmental Regulations
And Environmental Risks and Item 1. BusinessGovernmental Regulation and
Item 1. BusinessEnvironmental Matters. Risk Factors OUR LEVEL OF INDEBTEDNESS MAY ADVERSELY AFFECT OUR CASH AVAILABLE FOR
OPERATIONS, THUS LIMITING OUR GROWTH, OUR ABILITY TO MAKE INTEREST AND
PRINCIPAL PAYMENTS ON OUR INDEBTEDNESS AS THEY BECOME DUE AND OUR FLEXIBILITY
TO RESPOND TO MARKET CHANGES. Our level of indebtedness will have several important effects on our
operations, including those listed below.  
    
    We will dedicate a portion of our cash flow from operations to the
payment of interest on our indebtedness and to the payment of our other
current obligations, and will not have these cash flows available for
other purposes.
    
    The covenants in our credit facilities limit our ability to borrow
additional funds or dispose of assets and may affect our flexibility in
planning for, and reacting to, changes in business conditions.
    
    Our ability to obtain additional financing in the future for working
capital, capital expenditures, acquisitions, general corporate purposes
or other purposes may be impaired.
    
    We may be more vulnerable to economic downturns and our ability to
withstand sustained declines in oil and natural gas prices may be
impaired.
    
    Since our indebtedness is subject to variable interest rates, we are vulnerable to increases in interest rates.
    
    Our flexibility in planning for or reacting to changes in market conditions may be limited. We may incur additional debt in order to fund our exploration and development
activities. A higher level of indebtedness increases the risk that we may
default on our debt obligations. Our ability to meet our debt obligations and
reduce our level of indebtedness depends on future performance. General
economic conditions, oil and gas prices and financial, business and other
factors affect our operations and our future performance. Many of these factors
are beyond our control. We may not be able to generate sufficient cash flow to
pay the interest on our debt, and future working capital, borrowings and equity
financing may not be available to pay or refinance such debt. In addition, under the terms of our senior credit facility, our borrowing base
is subject to semi-annual redeterminations based in part on prevailing oil and
natural gas prices. In the event the amount outstanding exceeds the
redetermined borrowing base, we could be forced to repay a portion of our
borrowings. We may not have sufficient funds to make such payments. If we do
not have sufficient funds and are otherwise unable to negotiate renewals of our
borrowings or arrange new financing, we may have to sell significant assets. 42




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WE HAVE SUBSTANTIAL CAPITAL REQUIREMENTS FOR WHICH WE MAY NOT BE ABLE TO OBTAIN
ADEQUATE FINANCING. We make and will continue to make substantial capital expenditures in our
exploration and development projects. Without additional capital resources, our
drilling and other activities may be limited and our business, financial
condition and results of operations may suffer. We may not be able to secure
additional financing on reasonable terms or at all, and financing may not
continue to be available to us under our existing or new financing
arrangements. OIL AND NATURAL GAS PRICES FLUCTUATE WIDELY AND LOW PRICES COULD HAVE A
MATERIAL ADVERSE IMPACT ON OUR BUSINESS AND FINANCIAL RESULTS BY LIMITING OUR
LIQUIDITY AND FLEXIBILITY TO CARRY OUT OUR DRILLING PROGRAM. Our revenues, operating results and future rate of growth depend highly upon
the prices we receive for our oil and natural gas production. Historically, the
markets for oil and natural gas have been volatile and are likely to continue
to be volatile in the future. Market prices of oil and natural gas depend on
many factors beyond our control, including:  
    
    worldwide and domestic supplies of oil and natural gas;
    
    the ability of the members of the Organization of Petroleum Exporting
Countries to agree to and maintain oil price and production controls;
    
    political instability or armed conflict in oil-producing regions;
    
    the price and level of foreign imports;
    
    the level of consumer demand;
    
    the price and availability of alternative fuels;
    
    the availability of pipeline capacity;
    
    weather conditions;
    
    domestic and foreign governmental regulations and taxes; and
    
    the overall economic environment. We cannot predict future oil and natural gas price movements and prices often
vary significantly. Significant declines in oil and natural gas prices for an
extended period may have the following effects on our business:  
    
    limit our financial condition, liquidity, ability to finance planned capital expenditures and results of operations;
    
    reduce the amount of oil and natural gas that we can produce economically;
    
    cause us to delay or postpone some of our capital projects;
    
    reduce our revenues, operating income and cash flow; and
    
    reduce the carrying value of our oil and natural gas properties. OUR HEDGING TRANSACTIONS COULD REDUCE REVENUES IN A RISING COMMODITY PRICE
ENVIRONMENT OR EXPOSE US TO OTHER RISKS. In an attempt to reduce our sensitivity to energy price volatility, we may use
hedging arrangements that generally result in a fixed price or a range of
minimum and maximum price limits over a specified time period. Hedging
contracts limit the benefits we would otherwise realize if actual prices rise
above the contract price. Our hedging arrangements expose us to the risk of financial loss in certain
circumstances. For example, if we do not produce our oil 43




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and natural gas reserves at rates equivalent to our hedged position, we would
be required to satisfy our obligations under hedging contracts on potentially
unfavorable terms without the ability to hedge that risk through sales of
comparable quantities of our own production. This situation occurred during
portions of 2000, due in part to our sale of certain producing reserves in
mid-1999 and reduced our cash flow in 2000 by approximately $1 million.
Additionally, because the terms of our hedging contracts are based on
assumptions and estimates of numerous factors such as cost of production and
pipeline and other transportation and marketing costs to delivery points,
substantial differences between the hedged prices and our actual results could
harm our anticipated profit margins and our ability to manage the risk
associated with fluctuations in oil and natural gas prices. We also could be
financially harmed if the counter parties to our hedging contracts prove unable
or unwilling to perform their obligations under such contracts. Additionally,
in the past, some of our hedging contracts required us to deliver cash
collateral or other assurances of performance to the counter parties in the
event that our payment obligations exceeded certain levels. Future collateral
requirements are uncertain but will depend on arrangements with our counter
parties and highly volatile natural gas and oil prices. EXPLORATORY DRILLING IS A SPECULATIVE ACTIVITY THAT MAY NOT RESULT IN
COMMERCIALLY PRODUCTIVE RESERVES AND MAY REQUIRE EXPENDITURES IN EXCESS OF
BUDGETED AMOUNTS. Our future rate of growth depends highly upon the success of our exploratory
drilling program. Exploratory drilling involves a higher risk that we will not
encounter commercially productive natural gas or oil reservoirs than
developmental drilling. We cannot predict the cost of drilling, and we may be
forced to limit, delay or cancel drilling operations as a result of a variety
of factors, including:  
    
    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. We may not be successful in our future drilling activities because even with
the use of 3-D seismic and other advanced technologies, exploratory drilling is
a speculative activity. We could incur losses because our use of 3-D seismic
data and other advanced technologies requires greater pre-drilling expenditures
than traditional drilling strategies. Even when fully utilized and properly
interpreted, our 3-D seismic data and other advanced technologies only assist
us in identifying subsurface structures and do not indicate whether
hydrocarbons are in fact present in those structures. In addition, such seismic
interpretations are not substantiated without drilling which may even
invalidate previously accepted interpretations, require more processing and/or
interpretation expense or condemn an area. Because we interpret the areas
desirable for drilling from 3-D seismic data gathered over large areas, we may
not acquire option and lease rights until after the seismic data is available
and, in some cases, until the drilling locations are also identified. We may
never lease, drill or produce oil or natural gas from these or any other
potential drilling locations. We may not be successful in our drilling
activities, our overall drilling success rate for activity within a particular
province may not be maintained, and our completed wells may not ultimately
produce our estimated economically recoverable reserves. Unsuccessful drilling
activities could result in a significant decline in our production and revenues
and materially harm our operations and financial condition by reducing our
available cash and resources. WE ARE SUBJECT TO VARIOUS OPERATING AND OTHER CASUALTY RISKS THAT COULD RESULT
IN LIABILITY EXPOSURE OR THE LOSS OF PRODUCTION AND REVENUES. Our operations are subject to hazards and risks inherent in drilling for and
producing and transporting oil and natural gas, such as:  
    
    fires;
    
    natural disasters;
    
    formations with abnormal pressures;
    
    blowouts, cratering and explosions; and 44




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
    
    pipeline ruptures and spills. Any of these hazards and risks can result in the loss of hydrocarbons,
environmental pollution, personal injury claims and other damage to our
properties and the property of others. WE MAY NOT HAVE ENOUGH INSURANCE TO COVER ALL OF THE RISKS WE FACE, WHICH COULD
RESULT IN SIGNIFICANT FINANCIAL EXPOSURE. We maintain insurance coverage against some, but not all, potential losses in
order to protect against the risks we face. We may elect not to carry insurance
if our management believes that the cost of insurance is excessive relative to
the risks presented. If an event occurs that is not covered, or not fully
covered, by insurance, it could harm our financial condition and results of
operations. In addition, we cannot fully insure against pollution and
environmental risks. WE CANNOT CONTROL THE ACTIVITIES ON PROPERTIES WE DO NOT OPERATE AND ARE UNABLE
TO ENSURE THEIR PROPER OPERATION AND PROFITABILITY. We do not operate all of the properties in which we have an interest. As a
result, we have limited ability to exercise influence over operations for these
properties. The failure of an operator of our wells to adequately perform
operations, or an operators breach of the applicable agreements, could reduce
our production and revenues. The success and timing of our drilling and
development activities on properties operated by others therefore depends upon
a number of factors outside of our control, including the operators:  
    
    timing and amount of capital expenditures;
    
    expertise and financial resources;
    
    inclusion of other participants in drilling wells; and
    
    use of technology. THE MARKETABILITY OF OUR NATURAL GAS PRODUCTION DEPENDS ON FACILITIES THAT WE
TYPICALLY DO NOT OWN OR CONTROL WHICH COULD RESULT IN A CURTAILMENT OF
PRODUCTION AND REVENUES. The marketability of our production depends in part upon the availability,
proximity and capacity of natural gas gathering systems, pipelines and
processing facilities. We generally deliver natural gas through gas gathering
systems and gas pipelines that we do not own under interruptible or short term
transportation agreements. Under the interruptible transportation agreements,
the transportation of our gas may be interrupted due to capacity constraints on
the applicable system, for maintenance or repair of the system, or for other
reasons as dictated by the particular agreements. Our ability to produce and
market natural gas on a commercial basis could be harmed by any significant
change in the cost or availability of such markets, systems or pipelines. LOWER OIL AND NATURAL GAS PRICES MAY CAUSE US TO RECORD CEILING LIMITATION
WRITE-DOWNS WHICH WOULD REDUCE OUR STOCKHOLDERS EQUITY. We use the full cost method of accounting for costs related to our oil and gas
properties. Accordingly, we capitalize the cost to acquire, explore for and
develop oil and gas properties. Under full cost accounting rules, the net
capitalized cost of oil and gas properties may not exceed a ceiling limit
that is based upon the present value of estimated future net revenues from
proved reserves, discounted at 10%, plus the lower of the cost or fair market
value of unproved properties. If net capitalized costs of oil and gas
properties exceed the ceiling limit, we must charge the amount of the excess to
earnings. This is called a ceiling limitation write-down. This charge does
not impact cash flow from operating activities, but does reduce our
stockholders equity. The risk that we will be required to write down the
carrying value of our oil and gas properties increases when oil and gas prices
are low or volatile. In addition, write-downs may occur if we experience
substantial downward adjustments to our estimated proved reserves. Once
incurred, a write-down of oil and gas properties is not reversible at a later
date. WE HAVE HAD OPERATING LOSSES IN THE PAST AND MAY NOT BE PROFITABLE IN THE
FUTURE. We may not be profitable in the future. We have recognized the following annual
net losses since 1997: $1.1 million (including a net $1.2 million non-cash
deferred income tax charge incurred in connection with our conversion from a
partnership to a corporation) in 45




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1997, $33.3 million (including a $25.9 million non-cash write-down in the
carrying value of our oil and natural gas properties) in 1998, $21.6 million
(including a $12.2 million non-cash loss on the sale of oil and natural gas
properties) in 1999, and $15.7 million in 2000. OUR FUTURE OPERATING RESULTS MAY FLUCTUATE AND SIGNIFICANT DECLINES IN THEM
WOULD LIMIT OUR ABILITY TO INVEST IN PROJECTS. Our future operating results may fluctuate significantly depending upon a
number of factors, including:  
    
    industry conditions;
    
    prices of oil and natural gas;
    
    rates of drilling success;
    
    capital availability;
    
    rates of production from completed wells; and
    
    the timing and amount of capital expenditures. This variability could cause our business, financial condition and results of
operations to suffer. In addition, any failure or delay in the realization of
expected cash flows from operating activities could limit our ability to invest
and participate in economically attractive projects. THE FAILURE TO REPLACE RESERVES IN THE FUTURE WOULD ADVERSELY AFFECT OUR
PRODUCTION AND CASH FLOWS. In general, production from oil and natural gas properties declines as reserves
are depleted, with the rate of decline depending on reservoir characteristics.
Except to the extent we conduct successful exploration and development
activities or acquire properties containing proved reserves, or both, our
proved reserves and production will decline as reserves are produced. The business of exploring for or developing reserves is capital intensive.
Reductions in our cash flow from operations and limitations on or
unavailability of external sources of capital may impair our ability to make
the necessary capital investment to maintain or expand our asset base of oil
and natural gas reserves. In addition, our future exploration and development
activities may not result in additional proved reserves, and we may not be able
to drill productive wells at acceptable costs. WE ARE SUBJECT TO UNCERTAINTIES IN RESERVE ESTIMATES AND FUTURE NET CASH FLOWS. There is substantial uncertainty in estimating quantities of proved reserves
and projecting future production rates and the timing of development
expenditures. No one can measure underground accumulations of oil and natural
gas in an exact way. Accordingly, oil and natural gas reserve engineering
requires subjective estimations of those accumulations. Estimates of other
engineers might differ widely from those of our independent petroleum
engineers. Accuracy of reserve estimates depends on the quality of available
data and on engineering and geological interpretation and judgment. Our
independent petroleum engineers may make material changes to reserve estimates
based on the results of actual drilling, testing, and production. As a result,
our reserve estimates often differ from the quantities of oil and natural gas
we ultimately recover. Also, we make certain assumptions regarding future oil
and natural gas prices, production levels, and operating and development costs
that may prove incorrect. Any significant variance from these assumptions could
greatly affect our estimates of reserves, the economically recoverable
quantities of oil and natural gas attributable to any particular group of
properties, the classifications of reserves based on risk of recovery, and
estimates of the future net cash flows. Because most of our reserve estimates
are without the benefit of a lengthy production history and are calculated
using volumetric analysis, those estimates are less reliable than estimates
based on a lengthy production history. Volumetric analysis involves estimating
the volume of a reservoir based on the net feet of pay of the structure and an
estimation of the area covered by the structure based on seismic analysis. The present value of future net cash flows from our proved reserves is not
necessarily the same as the current market value of our estimated natural gas
and oil reserves. In accordance with the requirements of the Securities and
Exchange Commission, we base the estimated discounted future net cash flows
from our proved reserves on prices and costs on the day of estimate. However,
actual future net cash flows from our oil and natural gas properties also will
be affected by factors such as: 46




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
    
    actual prices we receive for oil and natural gas;
    
    the amount and timing of actual production;
    
    supply and demand for oil and natural gas;
    
    limits or increases in consumption by gas purchasers; and
    
    changes in governmental regulations or taxation. The timing of both our production and our incurrence of expenses in connection
with the development and production of oil and natural gas properties will
affect the timing of actual future net cash flows from proved reserves, and
thus their actual present value. In addition, the 10% discount factor we use
when calculating discounted future net cash flows in compliance with the
Securities and Exchange Commission reporting requirements may not be the most
appropriate discount factor based on interest rates in effect from time to time
and risks associated with us or the oil and gas industry in general. WE FACE SIGNIFICANT COMPETITION, AND MANY OF OUR COMPETITORS HAVE RESOURCES IN
EXCESS OF OUR AVAILABLE RESOURCES. We operate in the highly competitive areas of oil and natural gas exploration,
exploitation, acquisition and production. We face intense competition from a
large number of independent, technology-driven companies as well as both major
and other independent oil and natural gas companies in a number of areas such
as:  
    
    seeking to acquire desirable producing properties or new leases for future exploration;
    
    marketing our oil and natural gas production; and
    
    seeking to acquire the equipment and expertise necessary to operate and develop those properties. Many of our competitors have financial and other resources substantially in
excess of those available to us. This highly competitive environment could harm
our business. WE ARE SUBJECT TO VARIOUS GOVERNMENTAL REGULATIONS AND ENVIRONMENTAL RISKS
WHICH MAY CAUSE US TO INCUR SUBSTANTIAL COSTS. Our business is subject to laws and regulations promulgated by federal, state
and local authorities, including the FERC, the Environmental Protection Agency,
the Texas Railroad Commission, the TCEQ and the Oklahoma Corporation
Commission, relating to the exploration for, and the development, production
and marketing of, oil and natural gas, as well as safety matters. Legal
requirements are frequently changed and subject to interpretation, and we are
unable to predict the ultimate cost of compliance with these requirements or
their effect on our operations. We may be required to make significant
expenditures to comply with governmental laws and regulations. Our operations are subject to complex federal, state and local environmental
laws and regulations, including the CERCLA, the RCRA, the OPA and the Clean
Water Act. Environmental laws and regulations change frequently, and the
implementation of new, or the modification of existing, laws or regulations
could harm us. The discharge of natural gas, oil, or other pollutants into the
air, soil or water may give rise to significant liabilities on our part to the
government and third parties and may require us to incur substantial costs of
remediation. OUR BUSINESS MAY SUFFER IF WE LOSE KEY PERSONNEL. If we lose the services of our key management personnel or technical experts or
are unable to attract additional qualified personnel, our business, financial
condition, results of operations, development efforts and ability to grow could
suffer. We have assembled a team of geologists, geophysicists and engineers who
have considerable experience in applying 3-D seismic imaging technology to
explore for and to develop oil and natural gas. We depend upon the knowledge,
skill and experience of these experts to provide 3-D seismic imaging and to
assist us in reducing the risks associated with our participation in oil and
natural gas exploration and development projects. In addition, the success of
our business depends, to a significant extent, upon the abilities and continued
efforts of our management, particularly Ben M. Brigham, our Chief Executive
Officer, President and Chairman of the Board. We have an employment agreement with Mr. Brigham, but do not have an employment agreement
with any of our other employees. 47




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OUR SHARES THAT ARE ELIGIBLE FOR FUTURE SALE MAY HAVE AN ADVERSE EFFECT ON THE
PRICE OF OUR COMMON STOCK. Sales of substantial amounts of common stock, or a perception that such sales
could occur, could adversely affect the market price of the common stock and
could impair our ability to raise capital through the sale of our equity
securities. As of December 31, 2003, one of our stockholders, together with
its affiliates, owned 13,634,882 shares of our common stock. Furthermore, this
stockholder and other stockholders have the right to demand that we file a
registration statement under the Securities Act covering the sale of their
shares of common stock. CERTAIN OF OUR AFFILIATES CONTROL A MAJORITY OF OUR OUTSTANDING COMMON STOCK,
WHICH MAY AFFECT YOUR VOTE AS A STOCKHOLDER. Our directors, executive officers and 10% or greater stockholders, and certain
of their affiliates beneficially own a majority of our outstanding common
stock. Accordingly, these stockholders, as a group, will be able to control the
outcome of stockholder votes, including votes concerning the election of
directors, the adoption or amendment of provisions in our certificate of
incorporation or bylaws, and the approval of mergers and other significant
corporate transactions. The existence of these levels of ownership concentrated
in a few persons makes it unlikely that any other holder of common stock will
be able to affect our management or direction. These factors may also have the
effect of delaying or preventing a change in our management or voting control. CERTAIN ANTI-TAKEOVER PROVISIONS MAY AFFECT YOUR RIGHTS AS A STOCKHOLDER. Our certificate of incorporation authorizes our Board of Directors to issue up
to 10 million shares of preferred stock without stockholder approval and to set
the rights, preferences and other designations, including voting rights, of
those shares as the Board of Directors may determine. In addition, our
outstanding Series A preferred stock, our senior credit facility and our senior
subordinated notes contain terms restricting our ability to enter into change
of control transactions, including requirements to redeem or repay the Series A
preferred stock, our senior credit facility and our senior subordinated notes
upon a change in control. These provisions, alone or in combination with the
other matters described in the preceding paragraph may discourage transactions
involving actual or potential changes in our control, including transactions
that otherwise could involve payment of a premium over prevailing market prices
to holders of our common stock. We are also subject to provisions of the
Delaware General Corporation Law that may make some business combinations more
difficult. THE MARKET PRICE OF OUR STOCK IS VOLATILE. The trading price of our common stock and the price at which we may sell
securities in the future is subject to large fluctuations in response to any of
the following:  
    
    limited trading volume in our stock;
    
    changes in government regulations, quarterly variations in operating results;
    
    our involvement in litigation;
    
    general market conditions;
    
    the prices of oil and natural gas;
    
    announcements by us and our competitors;
    
    our liquidity;
    
    our ability to raise additional funds; and
    
    other events. 48




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Forward Looking Information This report and the documents incorporated by reference in this annual report on
Form 10-K contain forward-looking statements within the meaning of the federal
securities laws. These forward-looking statements include, among others, the following:  
    
    our growth strategies;
    
    our ability to successfully and economically explore for and develop oil and gas resources;
    
    anticipated trends in our business;
    
    our future results of operations;
    
    our liquidity and ability to finance our exploration and development activities;
    
    market conditions in the oil and gas industry;
    
    our ability to make and integrate acquisitions; and
    
    the impact of governmental regulation. Forward-looking statements are typically identified by use of terms such as
may, will, expect, anticipate, estimate and similar words, although
some forward-looking statements may be expressed differently. You should be aware that our actual results could differ materially from those
contained in the forward-looking statements. You should consider carefully the
statements under Risk Factors and other sections of this report, which
describe factors that could cause our actual results to differ from those set
forth in the forward-looking statements. 49




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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Management Opinion Concerning Derivative Instruments We use derivative instruments to manage exposure to commodity prices and
interest rate risks. Our objectives for holding derivatives are to achieve a
consistent level of cash flow to support a portion of our planned capital
spending. Our use of derivative instruments for hedging activities could
materially affect our results of operations in particular quarterly or annual
periods since such instruments can limit our ability to benefit from favorable
price movements. We do not enter into derivative instruments for trading
purposes. Fair Value of Derivative Contracts The fair value of our derivative contracts is determined based on
counterparties estimates and valuation models. We did not change our
valuation methodology during the year ended December 31, 2003. During 2003, we
were party to natural gas swap contracts, natural gas floor contracts, oil
swaps, oil collar contracts and interest rate swaps. See Notes to
the Consolidated Financial StatementsNote 12 for additional information regarding
our derivative contracts. The following table reconciles the changes that
occurred in the fair values of our open derivative contracts during 2003. Fair Value ofDerivativeContractsEstimated fair value of open contracts at December 31, 2002
    
    $
    (3,168
    )Change fair values of contractsFixed price natural gas swaps
    
    $
    (3,327
    )Natural gas collars
    
    
    (443
    )Fixed price oil swaps
    
    
    (1,318
    )Oil collars
    
    
    (501
    )Interest rate swap
    
    
    (112
    )Contract settlementsFixed price natural gas swaps
    
    $
    4,807Natural gas collars
    
    
    Fixed price oil swaps
    
    
    1,488Oil collars
    
    
    397Interest rate swap
    
    
    Estimated fair value of open contracts at December 31, 2003
    
    $
    (2,177
    )
 Based upon the market prices at December 31, 2003, we expect to transfer
approximately $2.1 million of the loss included on our balance sheet in
accumulated other comprehensive income (loss) to earnings during the next
twelve months when transactions actually occur. Commodity Price Risk Our primary commodity market risk exposure is to changes in the prices related
to the sale of our oil and natural gas production. The market prices for oil
and natural gas have been volatile and are likely to continue to be volatile in
the future. As such, we employ established policies and procedures to manage
our exposure to fluctuations in the sales prices we receive for our oil and
natural gas production using derivative instruments. We believe the use of derivative instruments, although not free of risk, allows
us to reduce our exposure to oil and natural gas sales price fluctuations and
thereby achieve a more predictable cash flow. While the use of derivative
instruments limits the downside risk of adverse price movements, their use may
also limit future revenues from favorable price movements. Moreover, our
hedging arrangements generally do not apply to all of our production and thus
provide only partial price protection against declines in commodity prices. We
expect that the amount of our hedges will vary from time to time. 50




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The gas derivative transactions are generally settled based upon the average of
the reporting settlement prices on the NYMEX for the last three trading days of
a particular contract month. The oil derivative transactions are generally
settled based on the average reporting settlement prices on the NYMEX for each
trading day of a particular calendar month. As of March 26, 2004, our oil and gas derivative instruments were comprised of
swaps and collars. For swap instruments, we receive a fixed price for the hedged commodity and pay
a floating market price, as defined in each instrument, to the counterparty.
These instruments are settled monthly. When the floating price exceeds the
fixed price for a contract month, we pay the counterparty. When the fixed price
exceeds the floating price, the counterparty is required to make a payment to
us. We have designated theses swap instruments as cash flow hedges designed to
achieve a more predictable cash flow, as well as reduce our exposure to price
volatility. For collar instruments, we establish a floor and ceiling price on future
commodity production. These instruments are settled monthly. When the
settlement price for a period is above the ceiling price, we pay the
counterparty. When the settlement price for a period is below the floor price,
the counterparty is required to pay us. We have designated these collar
instruments as cash flow hedges designed to achieve a more predictable cash
flow, as well as reduce our exposure to price volatility. The following table reflects our open natural gas derivative contracts at
December 31, 2003, the associated volumes and the corresponding weighted
average NYMEX reference price by quarter. 2004
    
    
    2005First
    
    
    Second
    
    
    Third
    
    
    Fourth
    
    
    First
    
    
    Second
    
    
    Third
    
    
    FourthQuarter
    
    
    Quarter
    
    
    Quarter
    
    
    Quarter
    
    
    Quarter
    
    
    Quarter
    
    
    Quarter
    
    
    QuarterNatural gas swaps:Volumes (MMbtu)
    
    
    295,750
    
    
    
    227,500
    
    
    
    138,000
    
    
    
    92,000
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Average price ($  per MMBtu)
    
    $
    4.963
    
    
    $
    4.252
    
    
    $
    4.180
    
    
    $
    4.360
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    Unrealized gain / (loss)
at 12/31/2003 ($ in
thousands)
    
    $
    (346
    )
    
    $
    (207
    )
    
    $
    (131
    )
    
    $
    (87
    )
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    Natural gas collars:Volumes (MMbtu)
    
    
    546,000
    
    
    
    409,500
    
    
    
    299,000
    
    
    
    230,000
    
    
    
    202,500
    
    
    
    136,500
    
    
    
    
    
    
    
    Average price ($  per MMBtu)Floor
    
    $
    4.125
    
    
    $
    4.139
    
    
    $
    4.135
    
    
    $
    4.150
    
    
    $
    4.139
    
    
    $
    4.083
    
    
    $
    
    
    
    $
    Ceiling
    
    
    8.433
    
    
    
    5.389
    
    
    
    5.350
    
    
    
    5.662
    
    
    
    6.633
    
    
    
    5.107
    
    
    
    
    
    
    
    Unrealized gain / (loss)
at 12/31/2003 ($ in
thousands)
    
    $
    (61
    )
    
    $
    (125
    )
    
    $
    (100
    )
    
    $
    (87
    )
    
    $
    (51
    )
    
    $
    (20
    )
    
    $
    
    
    
    $
    
 The following table reflects natural gas derivative contracts that were entered
into subsequent to December 31, 2003, the volumes associated with those
contracts and the corresponding weighted average NYMEX reference price by
quarter. 2004First
    
    
    Second
    
    
    Third
    
    
    FourthQuarter
    
    
    Quarter
    
    
    Quarter
    
    
    QuarterNatural gas collars:Volumes (MMbtu)
    
    
    
    
    
    
    100,100
    
    
    
    101,200
    
    
    
    34,100Average price ($  per MMBtu)Floor
    
    $
    
    
    
    $
    4.000
    
    
    $
    4.000
    
    
    $
    4.000Ceiling
    
    
    
    
    
    
    6.830
    
    
    
    6.830
    
    
    
    6.830
 51




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The following table reflects our open oil derivative contracts at December 31,
2003, the associated volumes and the corresponding weighted average NYMEX
reference price by quarter. 2004
    
    
    2005First
    
    
    Second
    
    
    Third
    
    
    Fourth
    
    
    First
    
    
    Second
    
    
    Third
    
    
    FourthQuarter
    
    
    Quarter
    
    
    Quarter
    
    
    Quarter
    
    
    Quarter
    
    
    Quarter
    
    
    Quarter
    
    
    QuarterOil swaps:Volumes (Bbls)
    
    
    29,575
    
    
    
    20,475
    
    
    
    13,800
    
    
    
    9,200
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Average price ($  per Bbl)
    
    $
    25.35
    
    
    $
    24.52
    
    
    $
    23.91
    
    
    $
    23.80
    
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    Unrealized gain / (loss)
at 12/31/2003 ($ in
thousands)
    
    $
    (206
    )
    
    $
    (129
    )
    
    $
    (76
    )
    
    $
    (45
    )
    
    $
    
    
    
    $
    
    
    
    $
    
    
    
    $
    Oil collars:Volumes (Bbls)
    
    
    45,500
    
    
    
    31,850
    
    
    
    18,40
    
    
    
    16,100
    
    
    
    15,750
    
    
    
    6,825
    
    
    
    
    
    
    
    Average price ($  per Bbl)Floor
    
    $
    23.00
    
    
    $
    23.00
    
    
    $
    23.00
    
    
    $
    23.00
    
    
    $
    23.00
    
    
    $
    23.00
    
    
    $
    
    
    
    $
    Ceiling
    
    
    30.43
    
    
    
    28.92
    
    
    
    27.00
    
    
    
    26.21
    
    
    
    25.85
    
    
    
    26.45
    
    
    
    
    
    
    
    Unrealized gain / (loss)
at 12/31/2003 ($ in
thousands)
    
    $
    (119
    )
    
    $
    (99
    )
    
    $
    (62
    )
    
    $
    (53
    )
    
    $
    (47
    )
    
    $
    (14
    )
    
    $
    
    
    
    $
    
 The following table reflects oil derivative contracts that were entered into
subsequent to December 31, 2003, the volumes associated with those contracts
and the corresponding weighted average NYMEX reference price by quarter. 2004First
    
    
    Second
    
    
    Third
    
    
    FourthQuarter
    
    
    Quarter
    
    
    Quarter
    
    
    QuarterOil collars:Volumes (Bbls)
    
    
    
    
    
    
    18,200
    
    
    
    18,400
    
    
    
    6,200Average price ($  per Bbl)Floor
    
    $
    
    
    
    $
    26.00
    
    
    $
    26.00
    
    
    $
    26.00Ceiling
    
    
    
    
    
    
    33.55
    
    
    
    33.55
    
    
    
    33.55
 Interest Rate Risk At December 31, 2003, we had $47.8 million in outstanding debt, of which $28.8
million was fixed rate debt. Our fixed rate debt consists of $20 million in
senior subordinated notes and $8.8 million in mandatorily redeemable Series A
preferred stock. The estimated fair value of our senior subordinated notes at December 31, 2003,
was $20.1 million. Dividends on our Series A preferred stock may be paid in cash at a rate of 6%
per annum or paid in kind through the issuance of additional shares of
preferred stock in lieu of cash at a rate of 8% per annum. Our option to pay
dividends in kind expires in November 2005. The carrying value
of the mandatorily redeemable Series A preferred stock approximates
its fair value as this is the amount that we would have to pay to
extinguish the preferred stock. The remaining $19 million in outstanding debt at December 31, 2003, was related
to borrowings under our senior credit facility. At our option, borrowings
under our senior credit facility bear interest at a rate equal to: (i) the base
rate of Société Générale plus a margin which fluctuates from 0.5% to 1.5%
depending on facility usage or (ii) LIBOR for one, two, three or six months
plus a margin which fluctuates from 1.5% to 2.5% depending on facility usage.
The weighted average interest rate on these borrowings at December 31, 2003,
was 2.7%. A 10% increase in short-term interest rates on the floating-rate
debt outstanding at December 31, 2003 would equal approximately 27 basis
points. Such an increase in interest rates would impact our annual interest
expense by approximately $51,000 assuming borrowed amounts under our senior
credit facilities remained at $19 million. As the interest rate on borrowings
outstanding under our senior credit facility is variable and is reflective of
current market conditions, the carrying value approximates the fair value. 52




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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Our Consolidated Financial Statements required by this item are included on the
pages immediately following the Index to Financial Statements appearing on page
F-1. 
 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 
 ITEM 9A. CONTROLS AND PROCEDURES Evaluation of Disclosure Controls and Procedures As of the end of period covered by this report, our principal executive officer
and principal financial officer carried out an evaluation of the effectiveness
of our disclosure controls and procedures. Based on their evaluation, they have
concluded that our disclosure controls and procedures effectively ensure that
the information required to be disclosed in the reports we file with the SEC is
recorded, processed, summarized and reported within the time periods specified
by the SEC. Changes in internal controls There were no changes in our internal controls or in other factors that have
materially affected, or are reasonably likely to materially affect, our
internal controls subsequent to the date of their evaluation of our disclosure
controls and procedures. 53




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PART III 
 ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by this item is incorporated by reference to
information under the caption Proposal OneElection of Directors and to the
information under the caption Section 16(a) Beneficial Ownership Reporting

Compliance in our 2004 Proxy Statement for our annual meeting of stockholders
to be held on June 3, 2004. The 2004 Proxy Statement will be filed with
the Securities and Exchange Commission not later than 120 days subsequent to
December 31, 2003. Pursuant to Item 401(b) of Regulation S-K, the information required by this
item with respect to Brighams executive officers is set forth in Part I of
this report. 
 ITEM 11. EXECUTIVE COMPENSATION The information required by this item is incorporated herein by reference to
the 2004 Proxy Statement, which will be filed with the Securities and Exchange
Commission not later than 120 days subsequent to December 31, 2003. 
 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by this item is incorporated herein by reference to
the 2004 Proxy Statement, which will be filed with the Securities and Exchange
Commission not later than 120 days subsequent to December 31, 2003. See Item
5. Market for Registrants Common Equity and Related Stockholder Matters, which
sets forth certain information with respect to our equity compensation plans. 
 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS The information required by this item is incorporated herein by reference to
the 2004 Proxy Statement, which will be filed with the Securities and Exchange
Commission not later than 120 days subsequent to December 31, 2003. 
 ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES The information required by this item is incorporated herein by reference to
the 2004 Proxy Statement, which will be filed with the Securities and Exchange
Commission not later than 120 days subsequent to December 31, 2003. 54




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PART IV 
 ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a)
    
    
    1.
    
    Consolidated Financial Statements:
See Index to Financial Statements on page F-1.2.
    
    
    No schedules are required3.
    
    
    Exhibits:The exhibits listed in the accompanying Index to Exhibits are
filed or incorporated by reference as part of the annual
report.(b)
    
    
    The following reports on Form 8-K were filed by Brigham during
the last quarter of the period covered by this Annual Report on Form
10-K:(1
    )
    
    Filed November 4, 2003 on Item 12. Regulation FD
Disclosure, Brigham issued a press release announcing that it
plans to force convert Series A preferred stock warrants.(2
    )
    
    Filed November 12, 2003 on Item 12. Regulation FD
Disclosure, Brigham issued a press release announcing its
financial results for the quarter ended September 30, 3003.(3
    )
    
    Filed December 8, 2003 on Item 5. Other Events,
regarding adoption of Rule 10b 5-1 (c) plans by certain
officers.(4
    )
    
    Filed December 16, 2003 on Item 12. Regulation FD
Disclosure, Brigham issued a press release announcing drilling
discoveries and provides operational update.
 55




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GLOSSARY OF OIL AND GAS TERMS The following are abbreviations and definitions of certain terms commonly used
in the oil and gas industry and in this report. The definitions of proved
developed reserves, proved reserves and proved undeveloped reserves have been
abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of
Regulation S-X. 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. All-Sources Finding Costs.The cost associated with acquiring and developing
proved oil and natural gas reserves determined on an Mcfe basis by dividing
total net capital expenditures, excluding proceeds from the sale of proved oil
and gas reserves, associated with drilling and completing of wells, acquiring
acreage and geological and geophysical work during the identified period, by
the estimated proved reserve additions from exploration and development
activities, acquisitions of proved reserves and revisions of previous estimates
during the same time period. Bbl.One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to oil or other liquid hydrocarbons. 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 or natural gas liquids. Completion.The installation of permanent equipment for the production of oil
or natural gas. Completion of the well does not necessarily mean the well will
be profitable. Completion Rate.The number of wells on which production casing has been run
for a completion attempt as a percentage of the number of wells drilled. Developed Acreage.The number of acres which are allocated or assignable to
producing wells or wells capable of production. Development Well.A well drilled within the proved area of an oil or natural
gas reservoir to the depth of a stratigraphic horizon known to be productive. 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. Fault.A break in the rocks along which there has been movement of one side
relative to the other side. Fault Block.A body of rocks bounded by one or more faults. Gross Acres or Gross Wells.The total acres or wells, as the case may be, in
which we have a working interest. Lease Operating Expenses.The expenses, usually recurring, which pay for
operating the wells and equipment on a producing lease. MBbl.One thousand barrels of oil or other liquid hydrocarbons. Mcf.One thousand cubic feet of natural gas. MMBbl.One million barrels of oil or other liquid hydrocarbons. Mcfe.One thousand cubic feet of natural gas equivalents. MMBtu.One million Btu, or British Thermal Units. One British Thermal Unit is
the quantity of heat required to raise the temperature of one pound of water by
one degree Fahrenheit. MMcf.One million cubic feet of natural gas. MMcfe.One million cubic feet of natural gas equivalents. 56




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##### Table of Contents



MMcfe/d.MMcfe per day. Net Acres or Net Wells.Gross acres or wells multiplied, in each case, by the
percentage working interest we own. Net Production.Production that we own less royalties and production due
others. Oil.Crude oil, condensate or other liquid hydrocarbons. Operator.The individual or company responsible for the exploration,
development, and production of an oil or gas well or lease. Pay.The vertical thickness of an oil and gas producing zone. Pay can be
measured as either gross pay, including non-productive zones or net pay,
including only zones that appear to be productive based upon logs and test
data. Pre-tax PV-10%.The pre-tax present value of estimated future revenues to be
generated from the production of proved reserves calculated in accordance with
Securities and Exchange Commission guidelines, net of estimated production and
future development costs, using prices and costs as of the date of estimation
without future escalation, without giving effect to non-property related
expenses such as general and administrative expenses, debt service and
depreciation, depletion and amortization, and discounted using an annual
discount rate of 10%. Proved Developed Reserves.Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods. Proved Reserves.The estimated quantities of crude oil, natural gas and natural
gas liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under
existing economic and operating conditions. Proved Undeveloped Reserves.Reserves that are expected to be recovered from
new wells on undrilled acreage or from existing wells where a relatively major
expenditure is required for recompletion. Reserve Replacement Rate.Estimated net reserves added to proved reserves
through extensions, discoveries and revisions, divided by production for the
period. Royalty.An interest in an oil and gas lease that gives the owner of the
interest the right to receive a portion of the production from the leased
acreage (or of the proceeds of the sale thereof), but generally does not
require the owner to pay any portion of the costs of drilling or operating the
wells on the leased acreage. Royalties may be either landowners royalties,
which are reserved by the owner of the leased acreage at the time the lease is
granted, or overriding royalties, which are usually reserved by an owner of the
leasehold in connection with a transfer to a subsequent owner. Spud.Start drilling a new well (or restart). Standardized Measure.The after-tax present value of estimated future revenues
to be generated from the production of proved reserves calculated in accordance
with Securities and Exchange Commission guidelines, net of estimated production
and future development costs, using prices and costs as of the date of
estimation without future escalation, without giving effect to non-property
related expenses such as general and administrative expenses, debt service and
depreciation, depletion and amortization, and discounted using an annual
discount rate of 10%. Trend.A geographical area that has been known to contain certain types of
combinations of reservoir rock, sealing rock and trap types containing
commercial amounts of hydrocarbons. Working Interest.An interest in an oil and gas lease that gives the owner of
the interest the right to drill for and produce oil and natural gas on the
leased acreage and requires the owner to pay a share of the costs of drilling
and production operations. 57




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SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, hereunder duly authorized, as of
March 26, 2004. Brigham Exploration CompanyBy:
    
    /s/ BEN M. BRIGHAMBen M. BrighamChief Executive Officer, President and Chairman of the Board
 Pursuant to the requirements of the Securities Exchange Act of 1934, the
following persons on behalf of the Registrant and in the capacity indicated
have signed this report below as of March 26, 2004. /s/ BEN M. BRIGHAM
Ben M. BrighamChief Executive Officer, President and
Chairman of the Board
(Principal Executive Officer)/s/ EUGENE B. SHEPHERD, JR.
Eugene B. Shepherd, Jr.Executive Vice President and
Chief Financial Officer
(Principal Financial and Accounting Officer)/s/ DAVID T. BRIGHAM
David T. BrighamExecutive Vice President  Land and Administration and Director/s/ HAROLD D. CARTER
Harold D. CarterDirector/s/ STEPHEN C. HURLEY
Stephen C. HurleyDirector/s/ STEPHEN P. REYNOLDS
Stephen P. ReynoldsDirector/s/ HOBART A. SMITH
Hobart A. SmithDirector/s/ STEVEN A. WEBSTER
Steven A. WebsterDirector/s/ R. GRAHAM WHALING
R. Graham WhalingDirector
 58




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##### Table of Contents



BRIGHAM EXPLORATION COMPANY 
 INDEX TO FINANCIAL STATEMENTS PageReport of Independent Auditors
    
    
    F-2Consolidated Balance Sheets as of December 31, 2003 and 2002
    
    
    F-3Consolidated Statements of Operations for the Years Ended December 31, 2003, 2002 and 2001
    
    
    F-4Consolidated Statements of Stockholders Equity for the Years Ended December 31, 2003, 2002 and 2001
    
    
    F-5Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001
    
    
    F-7Notes to the Consolidated Financial Statements
    
    
    F-8
                                               F-1




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##### Table of Contents



REPORT OF INDEPENDENT AUDITORS To the Board of Directors
and Stockholders of Brigham Exploration Company In our opinion, the accompanying consolidated balance sheets and the
related consolidated statements of operations, of stockholders equity and of
cash flows present fairly, in all material respects, the financial position of
Brigham Exploration Company (the Company) and its subsidiaries at December
31, 2003 and 2002, and the results of their operations and their cash flows for
the three years in the period ended December 31, 2003 in conformity with
accounting principles generally accepted in the United States of America. These
financial statements are the responsibility of the Companys management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States of America, 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 our opinion. Additionally, as discussed in Note 2 to the consolidated financial statements,
on January 1, 2003, the Company changed its method of accounting for its asset
retirement obligations in connection with its adoption of Statement of
Financial Accounting Standards (SFAS) No. 143, Accounting for Asset
Retirement Obligations. Additionally, as discussed in Note 2 to the
consolidated financial statements, on July 1, 2003, the Company changed its
method of accounting for its mandatorily redeemable preferred stock in
connection with its adoption of SFAS No. 150, Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity. /s/ PricewaterhouseCoopers LLP March 25, 2004
Houston, Texas F-2




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##### Table of Contents



BRIGHAM EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data) December 31,2003
    
    
    2002ASSETSCurrent assets:Cash and cash equivalents
    
    $
    5,779
    
    
    $
    15,318Accounts receivable
    
    
    11,143
    
    
    
    11,361Deferred income taxes
    
    
    307
    
    
    
    Other current assets
    
    
    3,606
    
    
    
    6,643Total current assets
    
    
    20,835
    
    
    
    33,322Oil and natural gas properties, using the full cost method of accountingProved
    
    
    277,351
    
    
    
    229,991Unproved
    
    
    38,506
    
    
    
    37,403Accumulated depletion
    
    
    (118,546
    )
    
    
    (102,414
    )197,311
    
    
    
    164,980Other property and equipment, net
    
    
    1,219
    
    
    
    1,234Deferred income taxes
    
    
    1,890
    
    
    
    Deferred loan fees
    
    
    2,501
    
    
    
    2,391Other noncurrent assets
    
    
    460
    
    
    
    132Total assets
    
    $
    224,216
    
    
    $
    202,059LIABILITIES AND STOCKHOLDERS EQUITYCurrent liabilities:Accounts payable
    
    $
    19,806
    
    
    $
    14,486Royalties payable
    
    
    5,280
    
    
    
    4,508Accrued drilling costs
    
    
    3,916
    
    
    
    2,727Participant advances received
    
    
    1,179
    
    
    
    1,955Other current liabilities
    
    
    5,398
    
    
    
    10,334Total current liabilities
    
    
    35,579
    
    
    
    34,010Senior credit facility
    
    
    19,000
    
    
    
    60,000Senior subordinated notes
    
    
    20,000
    
    
    
    21,797Series A Preferred Stock, mandatorily redeemable, $.01 par value, $20
stated and redemption value, 2,250,000 shares authorized, 439,722
shares issued and outstanding at December 31, 2003
    
    
    8,794
    
    
    
    Other noncurrent liabilities
    
    
    2,498
    
    
    
    186Commitments and contingenciesSeries A Preferred Stock, mandatorily redeemable, $.01 par value, $20
stated and redemption value, 2,250,000 shares authorized, 1,765,132
shares issued and outstanding at December 31, 2002
    
    
    
    
    
    
    19,540Series B Preferred Stock, mandatorily redeemable, $.01 par value, $20
stated and redemption value, 1,000,000 shares authorized, 501,226
shares issued and outstanding at December 31, 2002
    
    
    
    
    
    
    4,777Stockholders equity:Preferred stock, $.01 par value, 10 million shares authorized, of
which 2,250,000 and 1,000,000 shares are designated as Series A and
Series B, respectively
    
    
    
    
    
    
    Common stock, $.01 par value, 50 million shares authorized,
40,246,729 and 20,618,161 shares issued and 39,086,096 and
19,479,979 shares outstanding at December 31, 2003 and 2002,
respectively
    
    
    402
    
    
    
    206Additional paid-in capital
    
    
    151,263
    
    
    
    93,436Treasury stock, at cost; 1,160,633 and 1,138,182 shares at December
31, 2003 and 2002, respectively
    
    
    (4,402
    )
    
    
    (4,282
    )Unearned stock compensation
    
    
    (1,816
    )
    
    
    (212
    )Accumulated other comprehensive income (loss)
    
    
    (1,040
    )
    
    
    (3,047
    )Accumulated deficit
    
    
    (6,062
    )
    
    
    (24,352
    )Total stockholders equity
    
    
    138,345
    
    
    
    61,749Total liabilities and stockholders equity
    
    $
    224,216
    
    
    $
    202,059
 The accompanying notes are an integral part of these consolidated financial statements. F-3




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BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data) Year Ended December 31,2003
    
    
    2002
    
    
    2001Revenues:Oil and natural gas sales
    
    $
    51,545
    
    
    $
    35,100
    
    
    $
    32,293Other revenue
    
    
    132
    
    
    
    76
    
    
    
    25551,677
    
    
    
    35,176
    
    
    
    32,548Costs and expenses:Lease operating
    
    
    5,200
    
    
    
    3,759
    
    
    
    3,486Production taxes
    
    
    2,477
    
    
    
    1,977
    
    
    
    1,511General and administrative
    
    
    4,500
    
    
    
    4,971
    
    
    
    3,638Depletion of oil and natural gas properties
    
    
    16,972
    
    
    
    14,594
    
    
    
    13,211Depreciation and amortization
    
    
    629
    
    
    
    440
    
    
    
    677Accretion of discount on asset retirement obligations
    
    
    142
    
    
    
    
    
    
    
    29,920
    
    
    
    25,741
    
    
    
    22,523Operating income
    
    
    21,757
    
    
    
    9,435
    
    
    
    10,025Other income (expense):Interest income
    
    
    45
    
    
    
    119
    
    
    
    264Interest expense, net
    
    
    (4,815
    )
    
    
    (6,238
    )
    
    
    (6,681
    )Debt conversion expense
    
    
    
    
    
    
    (630
    )
    
    
    Other income (expense)
    
    
    (601
    )
    
    
    (310
    )
    
    
    8,080(5,371
    )
    
    
    (7,059
    )
    
    
    1,663Income before income taxes and cumulative effect of change in
accounting principle
    
    
    16,386
    
    
    
    2,376
    
    
    
    11,688Income tax benefit
    
    
    1,636
    
    
    
    
    
    
    
    Income before cumulative effect of change in accounting principle
    
    
    18,022
    
    
    
    2,376
    
    
    
    11,688Cumulative effect of change in accounting principle
    
    
    268
    
    
    
    
    
    
    
    Net income
    
    
    18,290
    
    
    
    2,376
    
    
    
    11,688Less accretion and dividends on redeemable preferred stock
    
    
    3,448
    
    
    
    2,952
    
    
    
    2,450Net income (loss) available to common stockholders
    
    $
    14,842
    
    
    $
    (576
    )
    
    $
    9,238Net income (loss) per share available to common stockholders:Basic:Income before cumulative effect of change in accounting principle
    
    $
    0.63
    
    
    $
    (0.04
    )
    
    $
    0.58Cumulative effect of change in accounting principle
    
    
    0.01
    
    
    
    
    
    
    
    $
    0.64
    
    
    $
    (0.04
    )
    
    $
    0.58Diluted:Income before cumulative effect of change in accounting principle
    
    $
    0.52
    
    
    $
    (0.04
    )
    
    $
    0.44Cumulative effect of change in accounting principle
    
    
    0.01
    
    
    
    
    
    
    
    $
    0.53
    
    
    $
    (0.04
    )
    
    $
    0.44
 The accompanying notes are an integral part of these consolidated financial statements. F-4




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BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
(in thousands) AccumulatedCommon Stock
    
    
    Additional 
Paid In
    
    
    Treasury
    
    
    Unearned 
Stock
    
    
    Other
Comprehensive
    
    
    Accumulated
    
    
    Total
StockholdersShares
    
    
    Amounts
    
    
    Capital
    
    
    Stock
    
    
    Compensation
    
    
    Income (Loss)
    
    
    Deficit
    
    
    EquityBalance, December 31, 2000
    
    
    17,030
    
    
    $
    170
    
    
    $
    78,274
    
    
    $
    (3,950
    )
    
    $
    (1,321
    )
    
    $
    
    
    
    $
    (38,416
    )
    
    $
    34,757Comprehensive income (loss):Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    11,688
    
    
    
    11,688Cumulative
effect (loss) on
adoption of SFAS 133
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (11,800
    )
    
    
    
    
    
    
    (11,800
    )Unrealized gain on cash
flow hedges
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    12,151
    
    
    
    
    
    
    
    12,151Comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    12,039Exercise of employee stock
options
    
    
    97
    
    
    
    1
    
    
    
    251
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    252Forfeitures of employee stock
options
    
    
    
    
    
    
    
    
    
    
    (115
    )
    
    
    
    
    
    
    31
    
    
    
    
    
    
    
    
    
    
    
    (84
    )Forfeitures of restricted stock
    
    
    
    
    
    
    
    
    
    
    6
    
    
    
    (148
    )
    
    
    121
    
    
    
    
    
    
    
    
    
    
    
    (21
    )Purchases of restricted stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (67
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (67
    )Issuance of warrants
    
    
    
    
    
    
    
    
    
    
    4,500
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    4,500In kind dividends on Series A
mandatorily 
redeemable
Preferred Stock
    
    
    
    
    
    
    
    
    
    
    (2,347
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (2,347
    )Accretion on Series A
mandatorily redeemable
Preferred Stock
    
    
    
    
    
    
    
    
    
    
    (103
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (103
    )Amortization of unearned stock
compensation
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    675
    
    
    
    
    
    
    
    
    
    
    
    675Balance, December 31, 2001
    
    
    17,127
    
    
    
    171
    
    
    
    80,466
    
    
    
    (4,165
    )
    
    
    (494
    )
    
    
    351
    
    
    
    (26,728
    )
    
    
    49,601Comprehensive income (loss):Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2,376
    
    
    
    2,376Unrealized loss on cash
flow hedges
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (3,519
    )
    
    
    
    
    
    
    (3,519
    )Net losses included in net
income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    121
    
    
    
    
    
    
    
    121Comprehensive income
(loss)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (1,022
    )Exercise of employee stock
options
    
    
    133
    
    
    
    1
    
    
    
    295
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    296Expiration of employee stock
options
    
    
    
    
    
    
    
    
    
    
    (46
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (46
    )Forfeitures of restricted stock
    
    
    
    
    
    
    
    
    
    
    (1
    )
    
    
    (41
    )
    
    
    15
    
    
    
    
    
    
    
    
    
    
    
    (27
    )Revision of terms of employee
stock options
    
    
    
    
    
    
    
    
    
    
    596
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    596Repurchases of common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (76
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (76
    )Issuance of warrants
    
    
    
    
    
    
    
    
    
    
    4,605
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    4,605Warrants exercised for common
stock
    
    
    244
    
    
    
    2
    
    
    
    623
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    625Common stock issued in
exchange for warrants and
convertible debt rights
    
    
    550
    
    
    
    6
    
    
    
    (56
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (50
    )Debt converted to common
stock
    
    
    2,564
    
    
    
    26
    
    
    
    9,906
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    9,932In kind dividends on Series A
mandatorily redeemable
preferred stock
    
    
    
    
    
    
    
    
    
    
    (2,689
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (2,689
    )Accretion on Series A
mandatorily redeemable
preferred stock
    
    
    
    
    
    
    
    
    
    
    (238
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (238
    )In kind dividends on Series B
mandatorily redeemable
preferred stock
    
    
    
    
    
    
    
    
    
    
    (24
    )
    

    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (24
    )Accretion on Series B
mandatorily redeemable
preferred stock
    
    
    
    
    
    
    
    
    
    
    (1
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (1
    )Amortization of unearned stock
compensation
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    267
    
    
    
    
    
    
    
    
    
    
    
    267Balance, December 31, 2002
    
    
    20,618
    
    
    $
    206
    
    
    $
    93,436
    
    
    $
    (4,282
    )
    
    $
    (212
    )
    
    $
    (3,047
    )
    
    $
    (24,352
    )
    
    $
    61,749
      F-5




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BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY (Continued)
(in thousands) Common Stock
    
    
    Additional
Paid In
    
    
    Treasury
    
    
    Unearned
Stock
    
    
    Accumulated
Other
Comprehensive
    
    
    Accumulated
    
    
    Total
StockholdersShares
    
    
    Amounts
    
    
    Capital
    
    
    Stock
    
    
    Compensation
    
    
    Income (Loss)
    
    
    Deficit
    
    
    EquityBalance, December 31, 2002
    
    
    20,618
    
    
    $
    206
    
    
    $
    93,436
    
    
    $
    (4,282
    )
    
    $
    (212
    )
    
    $
    (3,047
    )
    
    $
    (24,352
    )
    
    $
    61,749Comprehensive income (loss):Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    18,290
    
    
    
    18,290Unrealized gain on cash
flow hedges
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    991
    
    
    
    
    
    
    
    991Tax benefits related to
cash flow hedges
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    561
    
    
    
    
    
    
    
    561Net losses included in net
income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    455
    
    
    
    
    
    
    
    455Comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    

    
    
    20,297Issuance of common stock
    
    
    7,384
    
    
    
    74
    
    
    
    39,926
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    40,000Issuance of restricted stock
    
    
    
    
    
    
    
    
    
    
    1,831
    
    
    
    
    
    
    
    (1,831
    )
    
    
    
    
    
    
    
    
    
    
    Issuance of stock options
    
    
    
    
    
    
    
    
    
    
    296
    
    
    
    
    
    
    
    (296
    )
    
    
    
    
    
    
    
    
    
    
    Exercise of employee stock
options
    
    
    310
    
    
    
    3
    
    
    
    826
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    829Expiration of employee stock
options
    
    
    
    
    
    
    
    
    
    
    (19
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (19
    )Forfeitures of restricted stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (10
    )
    
    
    2
    
    
    
    
    
    
    
    
    
    
    
    (8
    )Repurchases of common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (110
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (110
    )Warrants exercised for common
stock
    
    
    11,935
    
    
    
    119
    
    
    
    18,415
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    18,534In kind dividends on Series A
mandatorily redeemable
preferred stock
    
    
    
    
    
    
    
    
    
    
    (2,350
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (2,350
    )Accretion on Series A
mandatorily redeemable
preferred stock
    
    
    
    
    
    
    
    
    
    
    (355
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (355
    )In kind dividends on Series B
mandatorily redeemable
preferred stock
    
    
    
    
    
    
    
    
    
    
    (711
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (711
    )Accretion on Series B
mandatorily redeemable
preferred stock
    
    
    
    
    
    
    
    
    
    
    (32
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (32
    )Amortization of unearned stock
compensation
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    521
    
    
    
    
    
    
    
    
    
    
    
    521Balance, December 31, 2003
    
    
    40,247
    
    
    $
    402
    
    
    $
    151,263
    
    
    $
    (4,402
    )
    
    $
    (1,816
    )
    
    $
    (1,040
    )
    
    $
    (6,062
    )
    
    $
    138,345
 The accompanying notes are an integral part of these consolidated financial statements. F-6




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BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands) Year Ended December 31,2003
    
    
    2002
    
    
    2001Cash flows from operating activities:Net income
    
    $
    18,290
    
    
    $
    2,376
    
    
    $
    11,688Adjustments to reconcile net income to cash provided (used) by operating
activities:Depletion of oil and natural gas properties
    
    
    16,972
    
    
    
    14,594
    
    
    
    13,211Depreciation and amortization
    
    
    629
    
    
    
    440
    
    
    
    677Interest paid through issuance of additional senior subordinated notes
    
    
    1,196
    
    
    
    1,076
    
    
    
    721Interest paid through issuance of additional mandatorily redeemable
preferred stock
    
    
    340
    
    
    
    
    
    
    
    Amortization of deferred loan fees
    
    
    1,053
    
    
    
    1,191
    
    
    
    1,372Accretion of discount on asset retirement obligations
    
    
    142
    
    
    
    
    
    
    
    Market value adjustment for derivative instruments
    
    
    669
    
    
    
    (263
    )
    
    
    (9,666
    )Loss on investment in Brigham Duke LLC
    
    
    
    
    
    
    
    
    
    
    94Stock option compensation expense
    
    
    
    
    
    
    596
    
    
    
    Deferred income taxes
    
    
    (1,636
    )
    
    
    
    
    
    
    Cumulative effect of change in accounting principle
    
    
    (268
    )
    
    
    
    
    
    
    Changes in working capital and other items:Accounts receivable
    
    
    218
    
    
    
    (2,248
    )
    
    
    164Other current assets
    
    
    3,037
    
    
    
    (4,534
    )
    
    
    (1,550
    )Accounts and royalties payable
    
    
    6,092
    
    
    
    10,703
    
    
    
    (920
    )Other current liabilities
    
    
    (4,975
    )
    
    
    5,060
    
    
    
    3,188Noncurrent assets
    
    
    
    
    
    
    2
    
    
    
    13Noncurrent liabilities
    
    
    (68
    )
    
    
    (20
    )
    
    
    (70
    )Net cash provided by operating activities
    
    
    41,691
    
    
    
    28,973
    
    
    
    18,922Cash flows from investing activities:Additions to oil and natural gas properties
    
    
    (45,842
    )
    
    
    (27,696
    )
    
    
    (34,532
    )Proceeds from sale of oil and natural gas properties
    
    
    427
    
    
    
    871
    
    
    
    397Additions to other property and equipment
    
    
    (349
    )
    
    
    (249
    )
    
    
    (396
    )(Increase) decrease in drilling advances paid
    
    
    (325
    )
    
    
    (132
    )
    
    
    960Net cash used by investing activities
    
    
    (46,089
    )
    
    
    (27,206
    )
    
    
    (33,571
    )Cash flows from financing activities:Proceeds from issuance of common stock, net of issuance costs
    
    
    40,000
    
    
    
    
    
    
    
    Redemption of Series B mandatorily redeemable preferred stock
    
    
    (704
    )
    
    
    
    
    
    
    Proceeds from issuance of preferred stock and warrants
    
    
    
    
    
    
    9,356
    
    
    
    9,838Proceeds from issuance of senior subordinated notes and warrants
    
    
    
    
    
    
    4,000
    
    
    
    9,000Proceeds from exercise of employee stock options
    
    
    829
    
    
    
    296
    
    
    
    252Proceeds from exercise of warrants
    
    
    
    
    
    
    625
    
    
    
    Fees paid due to common stock exchange for warrants
    
    
    
    
    
    
    (50
    )
    
    
    Repurchases of common stock
    
    
    (110
    )
    
    
    (76
    )
    
    
    (67
    )Increase in senior credit facility
    
    
    6,000
    
    
    
    
    
    
    
    Repayment of senior credit facility
    
    
    (47,000
    )
    
    
    (5,000
    )
    
    
    Principal payments on senior subordinated notes
    
    
    (2,993
    )
    
    
    
    
    
    
    Principal payments on capital lease obligations
    
    
    
    
    
    
    (28
    )
    
    
    (99
    )Deferred loan fees paid
    
    
    (1,163
    )
    
    
    (684
    )
    
    
    Net cash provided (used) by financing activities
    
    
    (5,141
    )
    
    
    8,439
    
    
    
    18,924Net increase (decrease) in cash and cash equivalents
    
    
    (9,539
    )
    
    
    10,206
    
    
    
    4,275Cash and cash equivalents, beginning of year
    
    
    15,318
    
    
    
    5,112
    
    
    
    837Cash and cash equivalents, end of year
    
    $
    5,779
    
    
    $
    15,318
    
    
    $
    5,112
 The accompanying notes are an integral part of these consolidated financial statements. F-7




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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 1. Organization and Nature of Operations Brigham Exploration Company is a Delaware corporation formed on February 25,
1997 for the purpose of exchanging its common stock for the common stock of
Brigham, Inc. and the partnership interests of Brigham Oil & Gas, L.P. (the
Partnership). Hereinafter, Brigham Exploration Company and the Partnership
are collectively referred to as Brigham. Brigham, Inc. is a Nevada
corporation whose only asset is its ownership interest in the Partnership. The
Partnership was formed in May 1992 to explore and develop onshore domestic oil
and natural gas properties using 3-D seismic imaging and other advanced
technologies. Since its inception, the Partnership has focused its exploration
and development of oil and natural gas properties primarily in the onshore Gulf
Coast, the Anadarko Basin and West Texas. 2. Summary of Significant Accounting Policies Use of Estimates The preparation of financial statements in conformity with generally accepted
accounting principles in the United States of America 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. The most significant estimates relate to proved
oil and natural gas reserve volumes and the future development costs as well as
estimates relating to certain oil and natural gas revenues and expenses. Actual
results may differ from those estimates. Principles of Consolidation The accompanying financial statements include the accounts of Brigham and its
wholly owned subsidiaries, and its proportionate share of assets, liabilities
and income and expenses of the limited partnerships in which Brigham, or any of
its subsidiaries has a participating interest. All significant intercompany
accounts and transactions have been eliminated. Cash and Cash Equivalents Brigham considers all highly liquid financial instruments with an original
maturity of three months or less to be cash equivalents. Property and Equipment Brigham uses the full cost method of accounting for oil and natural gas
properties. Under this method, all acquisition, exploration and development
costs, including payroll, asset retirement costs, other internal costs, and
interest incurred for the purpose of finding oil and natural gas reserves, are
capitalized. Internal costs capitalized are directly attributable to
acquisition, exploration and development activities and do not include costs
related to production, general corporate overhead or similar activities. Costs
associated with production and general corporate activities are expensed in the
period incurred. Proceeds from the sale of oil and natural gas properties are applied to reduce
the capitalized costs of oil and natural gas properties unless the sale would
significantly alter the relationship between capitalized costs and proved
reserves, in which case a gain or loss is recognized. Capitalized costs associated with impaired properties and capitalized costs
related to properties having proved reserves, plus the estimated costs of
future development and asset retirement costs under Statement of Financial
Accounting Standards No. 143 (SFAS 143), Accounting for Asset Retirement
Obligations are amortized using the unit-of-production method based on proved
reserves. Capitalized costs of oil and gas properties, net of accumulated
amortization, are limited to the total of estimated future net cash flows from
proved oil and natural gas reserves, discounted at ten percent, plus the cost
of unevaluated properties. There are many factors, including global events
that may influence the production, processing, marketing and valuation of oil and natural gas. F-8




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A reduction in the valuation of
oil and natural gas properties resulting from declining prices or production
could adversely impact depletion rates and capitalized cost
limitations. Capitalized costs associated with properties that have not been
evaluated through drilling or seismic analysis are excluded from the
unit-of-production amortization. Exclusions are adjusted annually based on
drilling results and interpretative analysis. Other property and equipment, which primarily consists of 3-D seismic
interpretation workstations, is depreciated on a straight-line basis over the
estimated useful lives of the assets after considering salvage value. Estimated
useful lives are as follows: Furniture and fixtures
    
    10 yearsMachinery and equipment
    
    5 years3-D seismic interpretation workstations and software
    
    3 years
 Betterments and major improvements that extend the useful lives are capitalized
while expenditures for repairs and maintenance of a minor nature are expensed
as incurred. Revenue Recognition Brigham recognizes crude oil revenues using the sales method of accounting.
Under this method, Brigham recognizes revenues when oil is delivered and title
transfers. Brigham recognizes natural gas revenues using the entitlements method of
accounting. Under this method, revenues are recognized based on Brighams
entitled ownership percentage of sales of natural gas to purchasers. Gas
imbalances occur when Brigham sells more or less than its entitled ownership
percentage of total natural gas production. When Brigham receives less than its
entitled share, a receivable is recorded. When Brigham receives more than its
entitled share, a liability is recorded. The following were recorded as of
December 31 (dollars in thousands): 2003
    
    2002Value
    
    MMcf
    
    Value
    
    MMcfGas imbalance receivable
    
    $
    2,477
    
    
    
    451
    
    
    $
    3,656
    
    
    
    1,180Gas imbalance payable
    
    
    2,064
    
    
    
    505
    
    
    
    5,650
    
    
    
    1,486
 Derivative Instruments and Hedging Activities Brigham uses derivative instruments to manage market risks resulting from
fluctuations in commodity prices of natural gas and crude oil. Brigham
periodically enters into commodity contracts, including price swaps, caps and
floors, which require payments to (or receipts from) counterparties based on
the differential between a fixed price and a variable price for a fixed
quantity of natural gas or crude oil without the exchange of underlying
volumes. The notional amounts of these financial instruments are based on
expected production from existing wells. On January 1, 2001, Brigham adopted Statement of Financial Accounting Standards
No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS
133), as amended. Effective with the adoption of SFAS 133, all derivatives are
recorded on the balance sheet at fair value and changes in the fair value of
derivatives are recorded each period in current earnings or other comprehensive
income, depending on whether a derivative is designated as part of a hedge
transaction and, if it is, depending on the type of hedge transaction.
Brighams derivatives consist primarily of cash flow hedge transactions in
which Brigham is hedging the variability of cash flows related to a forecasted
transaction. Changes in the fair value of these derivative instruments
designated as cash flow hedges are reported in other comprehensive income and
reclassified to earnings in the periods in which the contracts are settled. The
ineffective portion of the cash flow hedges is recognized in current period
earnings as other income (expense). Gains and losses on derivative instruments
that do not qualify for hedge accounting are included in other income (expense)
in the period in which they occur. The resulting cash flows from derivatives
are reported as cash flows from operating activities. The adoption of SFAS 133 resulted in a January 1, 2001 transition adjustment to
record a cumulative effect of $11.8 million to other comprehensive income to
recognize the fair value (liability) of all derivative instruments that
were previously deferred as adjustments to the carrying amount of hedged items
were not adjusted. F-9




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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) At the inception of a derivative contract, Brigham may designate the derivative
as a cash flow hedge. For all derivatives designated as cash flow hedges,
Brigham formally documents the relationship between the derivative contract and
the hedged items, as well as the risk management objective for entering into
the derivative contract. To be designated as a cash flow hedge transaction, the
relationship between the derivative and the hedged items must be highly
effective in achieving the offset of changes in cash flows attributable to the
risk both at the inception of the derivative and on an ongoing basis. Brigham
measures hedge effectiveness on a quarterly basis and hedge accounting is
discontinued prospectively if it is determined that the derivative is no longer
effective in offsetting changes in the cash flows of the hedged item. Gains and
losses deferred in accumulated other comprehensive income related to cash flow
hedge derivatives that become ineffective remain unchanged until the related
production is delivered. If Brigham determines that it is probable that a
hedged forecasted transaction will not occur, deferred gains or losses on the
hedging instrument are recognized in earnings immediately. See Note 12 for a
description of the derivative contracts in which Brigham participates. Other Comprehensive Income (Loss) Brigham follows the provisions of Statement of Financial Accounting Standards
No. 130, Reporting Comprehensive Income, which establishes standards for
reporting comprehensive income. In addition to net income, comprehensive income
includes all changes in equity during a period, except those resulting from
investments and distributions to stockholders of Brigham. Brigham had no such
changes prior to 2001. The components of other comprehensive income (loss) for the years ended
December 31, 2003, 2002 and 2001 follow (in thousands): 2003
    
    
    2002
    
    
    2001Balance, beginning of year
    
    $
    (3,047
    )
    
    $
    351
    
    
    $
    Cumulative effect of adoption of SFAS 133
    
    
    
    
    
    
    
    
    
    
    (11,800
    )Current period settlements reclassified to earnings
    
    
    6,692
    
    
    
    1,847
    
    
    
    9,646Current period change in fair value of hedges
    
    
    (5,701
    )
    
    
    (5,366
    )
    
    
    2,505Tax benefits related to cash flow hedges
    
    
    561
    
    
    
    
    
    
    
    Net losses included in earnings
    
    
    455
    
    
    
    121
    
    
    
    Balance, end of year
    
    $
    (1,040
    )
    
    $
    (3,047
    )
    
    $
    351
 Stock Based Compensation Brigham accounts for employee stock-based compensation using the intrinsic
value method prescribed by Accounting Principles Board Opinion No. 25,
Accounting for Stock Issued to Employees.  Accordingly, Brigham has adopted
the disclosure-only provisions of Statement of Financial Accounting Standards
No. 123, Accounting for Stock-Based Compensation (SFAS 123). F-10




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BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) Under SFAS 123, the fair value of each stock option grant is estimated on the
date of grant using the Black- Scholes option pricing model with the following
weighted average assumptions used for grants during the years ended December
31, 2003, 2002 and 2001: 2003
    
    
    2002
    
    
    2001Risk-free interest rate
    
    
    3.7
    %
    
    
    4.1
    %
    
    
    4.9
    %Expected life (in years)
    
    
    5
    
    
    
    7
    
    
    
    7Expected volatility
    
    
    48
    %
    
    
    102
    %
    
    
    60
    %Expected dividend yield
    
    
    
    
    
    
    
    
    
    
    Weighted average fair value per share of stock compensation
    
    $
    2.98
    
    
    $
    3.44
    
    
    $
    2.19
 The Black-Scholes valuation model was developed for use in estimating the fair
value of traded options that have no vesting restrictions and are transferable.
Additionally, the assumptions required by the valuation model are highly
subjective. Because Brighams stock options have significantly different
characteristics from those of traded options, and because changes in the
subjective input assumptions can materially affect the fair value estimate, in
managements opinion the model does not necessarily provide a reliable single
measure of the fair value of Brighams stock options. Had compensation cost for Brighams stock options been determined based on the
fair market value at the grant dates of the awards consistent with the
methodology prescribed by SFAS 123 as amended by SFAS 148, Brighams net income
(loss) and net income (loss) per share for the years ended December 31, 2003,
2002 and 2001 would have been the pro forma amounts indicated below: Year Ended December 31,2003
    
    
    2002
    
    
    2001Net income
(loss) available to common stockholders (in thousands):As reported
    
    $
    14,842
    
    
    $
    (576
    )
    
    $
    9,238Add back: Stock compensation expense
previously included in net income
    
    
    282
    
    
    
    101
    
    
    
    295Effect of total employee stock-based
compensation expense, determined under
fair value method for all awards
    
    
    (528
    )
    
    
    (513
    )
    
    
    (347
    )Pro forma
    
    $
    14,596
    
    
    $
    (988
    )
    
    $
    9,186Net income
(loss) per share:Basic:As reported
    
    $
    0.64
    
    
    $
    (0.04
    )
    
    $
    0.58Pro forma
    
    
    0.62
    
    
    
    (0.06
    )
    
    
    0.57Diluted:As reported
    
    $
    0.53
    
    
    $
    (0.04
    )
    
    $
    0.44Pro forma
    
    
    0.52
    
    
    
    (0.06
    )
    
    
    0.44
 Income Taxes Deferred tax assets and liabilities are recognized for the estimated future tax
consequences attributable to the differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases. Deferred tax assets and liabilities are measured using the tax rate in
effect for the year in which those temporary differences are expected to be
recovered or settled. The effect of a change in tax rates of deferred tax
assets and liabilities is recognized in income in the year of the enacted rate
change. Deferred tax assets are reduced by a valuation allowance when, in the
opinion of management, it is more likely than not that some portion or all of
the deferred tax assets will not be realized. F-11




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BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) Deferred Loan Fees The debt issue costs are amortized to interest expense over the life of the
debt using the straight-line method. The results obtained using the
straight-line method are not materially different than those that would result
from using the effective interest method. Segment Information All of Brighams oil and natural gas properties and related operations are
located onshore in the United States and management has determined that Brigham
has one reportable segment. Treasury Stock Treasury stock purchases are recorded at cost. Upon reissuance, the cost of
treasury shares held is reduced by the average purchase price per share of the
aggregate treasury shares held. New Pronouncements Statement of Financial Accounting Standards No. 141, Business Combinations
(SFAS 141) and Statement of Financial Accounting Standards, No. 142, Goodwill
and Intangible Assets (SFAS 142) were issued by the Financial Accounting
Standards Board (FASB) in June 2001 and became effective for Brigham on July 1,
2001 and January 1, 2002, respectively. SFAS 141 requires all business
combinations initiated after June 30, 2001 to be accounted for using the
purchase method. Additionally, SFAS 141 requires companies to disaggregate and
report separately from goodwill certain intangible assets. SFAS 142
establishes new guidelines for accounting for goodwill and other intangible
assets. Under SFAS 142, goodwill and certain other intangible assets are not
amortized, but rather are reviewed annually for impairment. The appropriate
application of SFAS 141 and 142 to oil and gas mineral rights held under lease
and other contractual arrangements representing the right to extract such
reserves is unclear. Depending on how the accounting and disclosure literature
is clarified, these oil and gas mineral rights held under lease and other
contractual arrangements representing the right to extract such reserves for
both undeveloped and developed leaseholds may be classified separately from oil
and gas properties, as intangible assets on our balance sheets. Additional
disclosures required by SFAS 141 and 142 would be included in the notes to
financial statements. Historically, Brigham, like many other oil and gas
companies, has included these oil and gas mineral rights held under lease and
other contractual arrangements representing the right to extract such reserves
as part of the oil and gas properties, even after SFAS 141 and 142 became
effective. This interpretation of SFAS 141 and 142 would only affect Brighams balance
sheet classification of oil and gas leaseholds. Brighams results of
operations and cash flows would not be affected, since these oil and gas
mineral rights held under lease and other contractual arrangements representing
the right to extract such reserves would continue to be amortized in accordance
with accounting rules for oil and gas companies provided in Statement of
Financial Accounting Standards No. 19, Financial Accounting and Reporting by
Oil and Gas Producing Companies. At December 31, 2003 Brigham had undeveloped leaseholds of approximately $4.2
million that would be classified on its balance sheet as intangible
undeveloped leasehold and developed leaseholds of an estimated $0.9 million
that would be classified as intangible developed leaseholds if Brigham
applied the interpretation currently being deliberated. This classification
would require the disclosures set forth under SFAS 142 related to these
interests. Brigham will continue to classify its oil and gas leaseholds as tangible oil
and gas properties until further guidance is provided. In
June 2001, the FASB issued SFAS 143 which requires entities to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. F-12




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BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) The liability is
accreted to its present value each period, and the capitalized cost is
depreciated over the useful life of the related asset. If the liability is
settled for an amount other than the recorded amount, a gain or loss is
recognized. Brigham adopted this standard as required on January 1, 2003. The
following pro forma data summarizes Brighams net income (loss) and net income
(loss) per share for the years ended December 31 2003, 2002 and 2001 as if
Brigham had adopted the provisions of SFAS 143 on January 1, 2001. The pro
forma asset retirement obligation as of January 1, 2001 would have been $1.7
million. Year Ended December 31,2003
    
    
    2002
    
    
    2001(in thousands, except per share amounts)Pro forma asset retirement obligations
    
     $
    2,320
    
    
    $
    1,961
    
    
     $
    1,680Net income (loss), as reported
    
     $
    14,842
    
    
    $
    (576
    )
    
     $
    9,238Pro forma adjustments to reflect
retroactive adoption of SFAS 143
    
    
    (268
    )
    
    
    155
    
    
    
    469Pro forma net income (loss)
    
     $
    14,574
    
    
    $
    (421
    )
    
     $
    9,707Net income (loss) per share:Basic  as reported
    
     $
    0.64
    
    
    $
    (0.04
    )
    
     $
    0.58Basic  pro forma
    
     $
    0.63
    
    
    $
    (0.03
    )
    
     $
    0.61Diluted  as reported
    
     $
    0.53
    
    
    $
    (0.04
    )
    
     $
    0.44Diluted  pro forma
    
     $
    0.52
    
    
    $
    (0.03
    )
    
     $
    0.46
 In April 2002, the FASB issued Statement of Financial Accounting Standards No.
145, Rescission of FASB statements No. 4, 44 and 64, Amendment of FASB
Statement No. 13 and Technical Corrections (SFAS 145). SFAS 145 requires,
except in the case of events or transactions of a highly unusual and infrequent
nature, gains or losses from the early extinguishment of debt to be classified
as components of a companys income or loss from continuing operations. Prior
to the adoption of the provisions of SFAS 145, gains or losses on the early
extinguishment of debt were required to be classified in a companys
consolidated statements of operations as extraordinary gains or losses, net of
associated income taxes, after the determination of income or loss from
continuing operations. SFAS 145 is effective for fiscal years beginning after
May 15, 2002. Due to the requirements of SFAS 145, it is less likely that a
gain or loss on extinguishment of debt would be classified as an extraordinary
item in Brighams results of operations. In May 2003, the FASB issued Statement of Financial Accounting Standards No.
150, Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity (SFAS 150). SFAS 150 requires an issuer to classify
certain financial instruments within its scope, such as mandatorily redeemable
preferred stock, as liabilities (or assets in some circumstances). Brigham
adopted this standard as required on July 1, 2003. Upon adoption, approximately
$8 million of the mandatorily redeemable Series A and B preferred stock were
within the scope of SFAS 150 and accordingly were reclassified to long term
debt and dividends on the reclassified amount of mandatorily redeemable Series
A and B preferred stock have been included in operations as additional interest
expense of approximately $340,000. The remaining approximate $18.3 million
balance of mandatorily redeemable preferred stock at July 1, 2003, was not
reclassified to long term debt because these instruments did not meet the
criteria of mandatorily redeemable financial instruments as defined by SFAS
150. SFAS 150 defines a financial instrument as mandatorily redeemable if it
embodies an unconditional obligation requiring the issuer to redeem the
instrument by transferring its assets at a specified or determinable date(s) or
upon an event certain to occur. The remaining balance of mandatorily
redeemable Series A and B preferred stock at July 1, 2003, did not embody an
unconditional obligation requiring Brigham to transfer its assets to redeem the
instruments. The $8 million reclassified to long term debt represents shares
of mandatorily redeemable Series A and B preferred stock that must be settled
with Brigham assets and thus are within the scope of SFAS 150. The vast
majority of these shares were issued to satisfy dividend requirements. F-13




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##### Table of Contents



BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) Reclassifications Certain reclassifications have been made to the prior year balances to conform
to current year presentation. 3. Asset Dispositions In February 1999, Brigham entered into a project financing arrangement with
Duke Energy Financial Services, Inc. (Duke) to fund the continued exploration
of five projects covered by approximately 200 square miles of 3-D seismic data
acquired in 1998. In this transaction, Brigham conveyed 100% of its working
interest in land and seismic in these project areas to a newly formed limited
liability company (the Brigham-Duke LLC) for a total consideration of $10
million. Brigham was the managing member of the Brigham-Duke LLC with a 1%
interest and Duke was the sole remaining member with a 99% interest. Pursuant
to the terms of the Brigham-Duke LLC agreement, Brigham paid 100% of the
drilling and completion costs for all wells drilled by the Brigham-Duke LLC in
exchange for a 70% working interest in the wells and their associated drilling
and spacing units and allocable seismic data. Upon 100% project payout, Brigham
had certain rights to back-in for up to a 94% effective working interest in the
Brigham-Duke LLC properties. In February 2001, Duke, as majority member of the
Brigham-Duke LLC, elected to dissolve the Brigham-Duke LLC. As a result of the
dissolution of the Brigham-Duke LLC, the remaining undeveloped land and seismic
data in the Brigham-Duke LLC project areas were unconditionally owned by Duke
and, in December 2001, Brigham recorded a loss of approximately $94,000 on its
investment in the Brigham-Duke LLC. 4. Property and Equipment Property and equipment, at cost, are summarized as follows (in thousands): December 31,2003
    
    
    2002Oil and natural gas properties
    
    $
    315,857
    
    
    $
    267,394Accumulated depletion
    
    
    (118,546
    )
    
    
    (102,414
    )197,311
    
    
    
    164,980Other property and equipment:3-D seismic interpretation workstations and software
    
    
    2,559
    
    
    
    2,445Office furniture and equipment
    
    
    2,572
    
    
    
    2,337Accumulated depreciation
    
    
    (3,912
    )
    
    
    (3,548
    )1,219
    
    
    
    1,234$
    198,530
    
    
    $
    166,214
 Brigham capitalizes certain payroll and other internal costs directly
attributable to acquisition, exploration and development activities as part of
its investment in oil and natural gas properties over the periods benefited by
these activities. Capitalized costs do not include any costs related to
production, general corporate overhead, or similar activities. Capitalized
costs are summarized as follows for the years ended December 31, 2003, 2002 and
2001 (in thousands): Year Ended December 31,2003
    
    
    2002
    
    
    2001Capitalized certain payroll and other internal costs
    
    $
    4,621
    
    
    $
    4,220
    
    
    $
    3,902Capitalized interest costs
    
    
    818
    
    
    
    878
    
    
    
    1,848$
    5,439
    
    
    $
    5,098
    
    
    $
    5,750
     F-14




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##### Table of Contents



BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) 5. Senior Credit Facility and Senior Subordinated Notes December 31,2003
    
    
    2002(in thousands)Senior Credit Facility
    
    $
    19,000
    
    
    $
    60,000Senior Subordinated Notes
    
    
    20,000
    
    
    
    21,797Total Debt
    
    $
    39,000
    
    
    $
    81,797Less: Current Maturities
    
    
    
    
    
    
    Total Long-Term Debt
    
    $
    39,000
    
    
    $
    81,797
 Senior Credit Facility As of December 31, 2003, Brigham had $19 million in borrowings outstanding
under its senior credit facility, which was put in place in March 2003. The
senior credit facility provides for a maximum $80 million in commitments, an
initial borrowing base of $70 million and matures in March 2006. Principal
outstanding under the senior credit facility is due at maturity, with interest
due quarterly for base rate tranches or periodically as London Interbank
Offered Rate (LIBOR) tranches mature. The annual interest rate for borrowings
under the senior credit facility is either the base rate of Société Générale or
LIBOR (1.1% on December 31, 2003), at Brighams option, plus a margin that
varies according to facility usage (1.55% on December 31, 2003). Obligations
under the senior credit facility are secured by substantially all of Brighams
oil and natural gas properties. The collateral value and borrowing base are redetermined periodically. Based
on the most recent redetermination effective December 1, 2003, the borrowing
base was set at $68.5 million. The unused portion of the committed borrowing
base is subject to an annual commitment fee of 0.5%. The senior credit facility agreement contains various covenants and
restrictive provisions, which limit Brighams ability to incur additional
indebtedness, sell properties, purchase or redeem capital stock, make
investments or loans, create liens and make certain acquisitions. The senior
credit facility requires Brigham to maintain a current ratio (as defined) of at
least 1 to 1 and an interest coverage ratio (as defined) of at least 3.25 to 1.
At December 31, 2003, and for the year then ended, Brigham was in compliance
with all covenant requirements in connection with its senior credit facility. Brighams prior senior credit facility was amended in February 2000, to provide
Brigham with $75 million in borrowing availability. As part of the amendment,
$30 million of the senior credit facility held by Shell Capital was designated
as convertible notes. To facilitate this conversion Brigham issued to Shell
Capital warrants to be converted into shares of Brigham common stock in the
following amounts and prices: (i) $10 million is convertible at $3.90 per
share, (ii) $10 million is convertible at $6.00 per share and (iii) $10 million
is convertible at $8.00 per share. In December 2002, Brigham entered into a series of transactions whereby a
number of warrants and convertible debt rights previously issued to Shell
Capital in connection with a prior amendment to the senior credit facility were
extinguished or converted. Brigham issued 550,000 unregistered shares of its
common stock to Shell Capital in exchange for Shell Capitals warrant position
(see Senior Subordinated Notes below), and to terminate Shell Capitals right
to convert $30 million of Brighams senior credit facility into shares of
Brigham common stock. Also, DLJ Merchant Banking Partners III, L.P. in
conjunction with GlobalEnergy Partners, both affiliates of CSFB Private Equity
(CSFB), purchased $10 million of Brighams senior credit facility from Shell
Capital and converted it into 2,564,102 shares of Brighams common stock at an
exercise price of $3.90 per share. Brigham recorded $0.6 million in debt
conversion expenses associated with this conversion. F-15




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##### Table of Contents



BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) The following table details the warrant position and convertible debt rights
that were extinguished or converted as a result of the these transactions: ExercisePrice
    
    
    Shares$10 million of Convertible Notes
    
    $
    3.90
    
    
    
    2,564,102$10 million of Convertible Notes
    
    $
    6.00
    
    
    
    1,666,667$10 million of Convertible Notes
    
    $
    8.00
    
    
    
    1,250,000Warrants issued with Senior Subordinated Notes Facility
    
    $
    3.00
    
    
    
    1,250,0006,730,769
 As further discussed in Note 6, in December 2002 Brigham also issued 500,000
shares of Series B preferred stock and warrants to purchase
2,298,850 million shares of Brighams common stock for net proceeds of $9.4 million. In addition,
Brigham used $5 million of the net proceeds from the Series B preferred
offering to repay outstanding indebtedness under its senior credit facility. Senior Subordinated Notes As of December 31, 2003, Brigham had $20 million of senior subordinated notes
outstanding. The senior subordinated notes are secured obligations ranking
junior to Brighams senior credit facility. The terms of the senior
subordinated notes were amended in March 2003 in order to have the covenants
and other features of the notes mirror those of the new senior credit facility
that was put in place simultaneously (see Senior Credit Facility above). The
terms of the senior subordinated notes were amended again in December 2003
resulting in a payment to reduce the outstanding balance of the notes to $20
million, reduce the interest rate and extend the maturity of the notes from
October 2005 until March 2009. Prior to the December 2003 amendment, the
senior subordinated notes bore interest at 10.75% per annum, were redeemable at
Brighams option for face value at any time and had no principal repayment
obligations. As a consequence of the December 2003 amendment, the 10.75% fixed
rate coupon was converted to a floating rate coupon. Simultaneous with the
completion of the amendment, Brigham entered into an interest rate swap
contract to fix the coupon at 8.76% through the new maturity date. In
connection with the December 2003 amendment, Brigham agreed to an additional
covenant, which requires that Brigham maintain a ratio of risked net present
value discounted at 9% to total debt of 1.5 to 1 as defined. Through October 2003, Brigham had the option to pay up to 50% of the interest
payments on the senior subordinated notes through the issuance of additional
senior subordinated notes in lieu of cash. For the years ended December 31,
2003, 2002 and 2001, Brigham exercised this option and issued an additional
$1.2, $1.1 and $0.7 million, respectively, of senior subordinated notes. At December 31, 2003 and for the year then ended, Brigham was in compliance
with all covenant requirements in connection with its senior subordinated
notes. In connection with the original senior subordinated credit agreement entered
into in October 2000, Brigham issued warrants to purchase 1,250,000 shares of
Brigham common stock at an exercise price of $3.00 per share. The warrants had
a term of seven years and a cashless exercise feature. Brigham valued the
warrants using the Black-Scholes Option Pricing Model and recorded the
estimated value of $2.9 million as deferred loan costs which are being
amortized as interest expense over the term of the senior subordinated notes.
The warrants were extinguished in December 2002 (see Senior Credit Facility
above). F-16




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##### Table of Contents



BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) 6. Preferred Stock Series A Mandatorily Redeemable Preferred Stock The following table reflects the outstanding shares of Series A mandatorily
redeemable preferred stock and the activity related thereto for the years ended
December 31, 2003 and 2002 (in thousands, except share amounts): Year Ended
    
    
    Year EndedDecember 31, 2003
    
    
    December 31, 2002Shares
    
    
    Amounts
    
    
    Shares
    
    
    AmountsSeries A mandatorily redeemable preferred stock:Balance, beginning of year
    
    
    1,765,132
    
    
    $
    19,540
    
    
    
    1,630,692
    
    
    $
    16,613Dividends paid in kind
    
    
    132,490
    
    
    
    2,650
    
    
    
    134,440
    
    
    
    2,689Accretion
    
    
    
    
    
    
    355
    
    
    
    
    
    
    
    238132,490
    
    
    
    3,005
    
    
    
    134,440
    
    
    
    2,927Forced redemption of October 2000 issuance
    
    
    (1,000,002
    )
    
    
    (9,060
    )
    
    
    
    
    
    
    Forced redemption of March 2001 issuance
    
    
    (457,898
    )
    
    
    (4,691
    )
    
    
    
    
    
    
    (1,457,900
    )
    
    
    (13,751
    )
    
    
    
    
    
    
    Balance, end of year
    
    
    439,722
    
    
    $
    8,794
    
    
    
    1,765,132
    
    
    $
    19,540
 In October 2000, Brigham designated 1,500,000 shares of preferred stock as
Series A Preferred Stock, and in November 2000, issued 1,000,000 shares of
mandatorily redeemable preferred stock (Series A Preferred Stock) and warrants
to purchase 6,666,667 shares of Brighams common stock (Series A  Tranche 1
Warrants) for net proceeds of $19.8 million. The Series A Preferred Stock has a par value of $.01 per share and a stated
value of $20 per share. The Series A Preferred Stock is cumulative and pays
dividends quarterly at a rate of 6% per annum of the stated value if paid in
cash or 8% per annum of the stated value if paid in kind (PIK) through the
issuance of additional Series A Preferred Stock in lieu of cash. At Brighams
option, up to 100% of the dividend payments on the Series A Preferred Stock can
be paid by the issuance of PIK dividends through October 2005. The Series A
Preferred Stock matures in November 2010 and is redeemable at Brighams option
at 100% or 101% of stated value (depending upon certain conditions) at anytime
prior to maturity. The Series A Preferred Stock does not generally have any
voting rights, except for certain approval rights and as required by law. The Series A  Tranche 1 Warrants were issued with a term of ten years, an
exercise price of $3.00 per share and a right that allowed Brigham to require
the exercise of the warrants in the event Brighams common stock traded above
$5.00 per share for 60 consecutive trading days. The exercise price of the
Series A  Tranche 1 Warrants was payable either in cash or in shares of the
Series A Preferred Stock valued at liquidation value plus accrued dividends.
The Series A  Tranche 1 Warrants were valued at $11.5 million using the
Black-Scholes Option Pricing model and were recorded as additional paid-in
capital in 2000. This discount accreted to the Series A Preferred Stock
dividends during the life of the securities using the effective interest
method. In November 2003, Brighams common stock traded at an average above $5.00 per
share for 60 consecutive trading days and Brigham notified CSFB of its intent
to force the exercise of the warrants. The warrants were exercised using
shares of Series A Preferred Stock and Brigham received no additional proceeds
from the exercise of the warrants. F-17




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##### Table of Contents



BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) In March 2001, Brigham designated an additional 750,000 shares of preferred
stock as Series A Preferred Stock and issued 500,000 shares of Series A
Preferred Stock and 2,105,263 warrants to purchase Brighams common stock
(Series A  Tranche 2 Warrants) to CSFB for net proceeds of $9.8 million. The Series A  Tranche 2 Warrants, which had terms similar to the Series A 
Tranche 1 Warrants, had an exercise price of $4.75 per share, later reset to
$4.35 in connection with the issuance of Series B Preferred Stock in December
2002, and a right that allowed Brigham to require the exercise of the warrants
in the event that Brighams common stock traded at an average of at least 150%
of the exercise price ($6.525 per share) for 60 consecutive trading days. The
Series A  Tranche 2 Warrants were valued at approximately $4.5 million using
the Black-Scholes Option Pricing model and were recorded as additional paid-in
capital in March 2001. This discount accreted to the Series A Preferred Stock
dividends during the life of the securities using the effective interest
method. In November 2003, the price of Brighams common stock averaged at least $6.525
per share for 60 consecutive trading days and Brigham notified CSFB of its
intent to force the exercise of the warrants. The warrants were exercised
using shares of Series A Preferred Stock and Brigham received no additional
proceeds from the exercise of the warrants. The remaining balance of Series A mandatorily redeemable preferred stock has a
mandatory redemption date of October 31, 2010. Series B Mandatorily Redeemable Preferred Stock The following table reflects the outstanding shares of Series B mandatorily
redeemable preferred stock and the activity related thereto for the years ended
December 31, 2003 and 2002 (in thousands, except share amounts): Year Ended
    
    
    Year EndedDecember 31, 2003
    
    
    December 31, 2002Shares
    
    
    Amounts
    
    
    Shares
    
    
    AmountsSeries B mandatorily redeemable preferred stock:Balance, beginning of year
    
    
    501,226
    
    
    $
    4,777
    
    
    
    
    
    
    $
    Issuance of shares
    
    
    
    
    
    
    
    
    
    
    500,000
    
    
    
    4,752Dividends paid in kind
    
    
    30,603
    
    
    
    612
    
    
    
    1,226
    
    
    
    24Accretion
    
    
    
    
    
    
    32
    
    
    
    
    
    
    
    130,603
    
    
    
    644
    
    
    
    1,226
    
    
    
    25Forced redemption of December 2002 issuance
    
    
    (500,002
    )
    
    
    (4,784
    )
    
    
    
    
    
    
    Final redemption of remaining shares
    
    
    (31,827
    )
    
    
    (637
    )
    
    
    
    
    
    
    (531,829
    )
    
    
    (5,421
    )
    
    
    
    
    
    
    Balance, end of year
    
    
    
    
    
    $
    
    
    
    
    501,226
    
    
    $
    4,777
 In December 2002, Brigham designated 1,000,000 shares of preferred stock as
Series B and issued 500,000 shares of Series B Preferred Stock and warrants to
purchase 2,298,851 shares of Brighams common stock (Series B Warrants) to CSFB
for net proceeds of $9.4 million. Brigham used $5 million of the net proceeds
to reduce borrowings under the senior credit facility. The Series B Preferred
Stock is cumulative and pays dividends quarterly at a rate of 6% per annum of
the stated value if paid in cash or 8% per annum of the stated value if PIK
through the issuance of additional Series B Preferred Stock in lieu of cash. At
Brighams option, up to 100% of the dividend payments on the Series B Preferred
Stock can be paid by the issuance of PIK dividends for five years. The Series B
Preferred Stock matures in ten years and is redeemable in whole at Brighams
option at 101% of the stated value five years after closing. F-18




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##### Table of Contents



BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) The Series B Preferred Stock ranks in parity with the Series A Preferred Stock
and senior as to dividend, redemption and liquidation rights to all other
classes and series of capital stock of Brigham authorized on the date of
issuance, or to any other class or series of capital stock issued while any
shares of the Series B Preferred Stock remain outstanding. The Series B
Preferred Stock does not generally have any voting rights, except for certain
approval rights and as required by law. The Series B Warrants had terms similar to the Series A Warrants described
above with an exercise price of $4.35 per share and a right that allowed
Brigham to require the exercise of the warrants in the event that Brighams
common stock traded at an average of at least 150% of the exercise price
($6.525 per share) for 60 consecutive trading days. The Series B Warrants were
valued at approximately $4.6 million using the Black-Scholes Option Pricing
model and were recorded as additional paid-in capital in December 2002. This
discount accreted to the Series B Preferred Stock dividends during the life of
the securities using the effective interest method. In November 2003, the price of Brighams common stock averaged at least $6.525
per share for 60 consecutive trading days and Brigham notified CSFB of its
intent to force the exercise of the warrants. The exercise price was paid in
shares of Series B Preferred Stock and Brigham received no additional proceeds
from the exercise of the warrants. Under the terms of the Series B Preferred
Stock, Brigham was required to retire the remaining shares of Series B
Preferred Stock plus accrued dividends upon the exercise of the warrants
because the warrants were exercised using shares of Series B Preferred Stock. 7. Issuance of Common Stock In December 2003, Brigham issued 2,105,263 shares of Brigham common stock
pursuant to the exercise of the Series A  Tranche 2 warrants and 2,298,850
shares of Brigham common stock pursuant to the exercise of the Series B
warrants to CSFB. See further discussion above in Note 6. In November 2003, Brigham issued 6,666,667 shares of Brigham common stock
pursuant to the exercise of the Series A  Tranche 1 warrants to CSFB. See
further discussion above in Note 6. In September 2003, Brigham issued 7,384,090 shares of Brigham common stock in a
public offering and received proceeds of approximately $40 million, net of
underwriting commissions and other offering expenses. The proceeds of the
offering will be used to accelerate exploration and development activities and
for general corporate purposes. Following the offering, proceeds were used to
pay down the new senior credit facility. In June 2003, Brigham issued 206,982 and 408,928 shares of Brigham common stock
pursuant to the exercise under a cashless feature of 338,462 and 661,538
warrants, respectively. In December 2002, Brigham issued 550,000 shares of Brigham common stock to
Shell Capital in exchange for Shell Capitals warrants and associated
convertible debt rights. In addition, Brigham issued 2,564,102 shares of
Brigham common stock upon the conversion of $10 million of the senior credit
facility. See further discussion above in Note 5. In February 2000, Brigham issued 2,195,122 shares of Brigham common stock and
warrants to purchase 731,707 shares of Brighams common stock for total net
proceeds of approximately $4.2 million in a private placement to a group of
institutional investors led by affiliates of two members of Brighams board of
directors. The equity sale consisted of units that included one share of common
stock and one-third of a warrant to purchase Brighams common stock at an
exercise price of $2.5625 per share. In December 2002, 243,902 of these
warrants were exercised for common stock resulting in net proceeds of
approximately $625,000. In February 2003, the remaining 487,805 warrants were
exercised under a cashless feature resulting in the issuance of 248,028 shares
of Brigham common stock. F-19




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##### Table of Contents



BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) 8. Asset Retirement Obligations As referred to in Note 2, Brigham adopted the provisions of SFAS 143 on January
1, 2003. Brigham has asset retirement obligations associated with the future
plugging and abandonment of proved properties and related facilities. Prior to
the adoption of SFAS 143, Brigham assumed salvage value approximated plugging
and abandonment costs. As such, estimated salvage value was not excluded from
depletion and plugging and abandonment costs were not accrued for over the life
of the oil and gas properties. The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect
adjustment to record (i) a $1.4 million increase in the carrying values of
proved properties, (ii) a $0.8 million decrease in accumulated depletion of oil
and natural gas properties and (iii) a $1.9 million increase in other
noncurrent liabilities. The net impact of items (i) through (iii) was to record
a gain of $0.3 million as a cumulative effect adjustment of a change in
accounting principle in Brighams consolidated statements of operations upon
adoption on January 1, 2003. Brigham has no assets that are legally restricted for purposes of settling
asset retirement obligations. The following table summarizes Brighams asset
retirement obligation transactions recorded in accordance with the provisions
of SFAS 143 during the year ended December 31, 2003 (in thousands): Year EndedDecember 31, 2003Beginning asset retirement obligations
    
    $
    1,931Liabilities incurred for new wells placed on production
    
    
    269Liabilities settled
    
    
    (22
    )Accretion of discount on asset retirement obligations
    
    
    142$
    2,320
 9. Income Taxes The benefit for income taxes consists of the following (in thousands): Year Ended December 31,2003
    
    
    2002
    
    
    2001Current income taxes:Federal
    
    $
    
    
    
    $
    
    
    
    $
    State
    
    
    
    
    
    
    
    
    
    
    Deferred income taxes:Federal
    
    
    (1,636
    )
    
    
    
    
    
    
    State
    
    
    
    
    
    
    
    
    
    
    $
    (1,636
    )
    
    $
    
    
    
    $
    
 The differences in income taxes provided and the amounts determined by applying
the federal statutory tax rate to income before income taxes result from the
following (in thousands): Year Ended December 31,2003
    
    
    2002
    
    
    2001Tax at statutory rate
    
    $
    5,735
    
    
    $
    832
    
    
    $
    4,091Add the effect of:Nondeductible expenses
    
    
    5
    
    
    
    223
    
    
    
    4Deductible stock compensation
    
    
    (118
    )
    
    
    (110
    )
    
    
    (9
    )Valuation
allowance adjustments
    
    
    (7,352
    )
    
    
    (945
    )
    
    
    (4,086
    )Other
    
    
    94
    
    
    
    
    
    
    
    $
    (1,636
    )
    
    $
    
    
    
    $
    
     F-20




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##### Table of Contents



BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) The components of deferred income tax assets and liabilities are as follows (in
thousands): December 31,2003
    
    2002Deferred tax assetsCurrent:Net operating loss carryforwards
    
    $
    451
    
    
    $
    Noncurrent:Net operating loss carryforwards
    
    
    34,409
    
    
    
    34,814Capital loss carryforwards
    
    
    634
    
    
    
    634Stock compensation
    
    
    818
    
    
    
    808Gas imbalances
    
    
    
    
    
    
    698Unrealized hedging losses
    
    
    561
    
    
    
    1,066Derivative assets
    
    
    276
    
    
    
    42Asset retirement obligations
    
    
    812
    
    
    
    Preferred stock dividends as interest expense
    
    
    119
    
    
    
    Other
    
    
    27
    
    
    
    32Noncurrent
    
    
    37,656
    
    
    
    38,09438,107
    
    
    
    38,094Deferred tax liabilitiesCurrent:Gas imbalances
    
    
    (144
    )
    
    
    Noncurrent:Depreciable and depletable property
    
    
    (35,132
    )
    
    
    (29,544
    )Derivative liabilities
    
    
    
    
    
    
    Noncurrent
    
    
    (35,132
    )
    
    
    (29,544
    )(35,276
    )
    
    
    (29,544
    )Net deferred tax asset
    
    
    2,831
    
    
    
    8,550Valuation allowance
    
    
    (634
    )
    
    
    (8,550
    )$
    2,197
    
    
    $
    
 Realization of deferred tax assets associated with (i) net operating loss
carryforwards (NOLs) and (ii) existing temporary differences between book and
taxable income is dependent upon generating sufficient taxable income within
the carryforward period available under tax law. At December 31, 2003,
management believes that Brigham will (i) begin to utilize NOLs and (ii) have
reversals of existing temporary differences between book and taxable income
sufficient to recognize a benefit in 2003. Management also believes that it is
more likely than not that capital loss carryforwards of approximately $1.8
million may expire unused and, accordingly, has established a valuation
allowance of $0.6 million. At December 31, 2003, Brigham has regular tax NOLs of approximately $99.6
million. Additionally, Brigham has approximately $85.2 million of alternative
minimum tax (AMT) NOLs available as a deduction against future taxable income. F-21




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##### Table of Contents



BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) The NOLs expire from 2012 through 2023. The value of these NOLs depends
on the ability of Brigham to generate taxable income. A summary of the NOLs
follows: Regular
    
    
    AMTNOLs
    
    
    NOLsExpiration Date:December 31, 2012
    
    $
    13,299
    
    
    $
    8,675December 31, 2018
    
    
    26,411
    
    
    
    23,170December 31, 2019
    
    
    20,717
    
    
    
    20,107December 31, 2020
    
    
    12,491
    
    
    
    7,566December 31, 2021
    
    
    19,095
    
    
    
    18,419December 31, 2022
    
    
    4,452
    
    
    
    4,114December 31, 2023
    
    
    3,136
    
    
    
    3,142$
    99,601
    
    
    $
    85,193
 In addition, at December 31, 2003, Brigham has capital loss carryforwards of
approximately $1.8 million that expire in varying years through 2007. Brigham believes it has a $4.5 million limitation on its NOLs under Internal
Revenue Code Section 382 due to a potential 50% change in ownership among its
5% shareholders over a three-year period. 10. Net Income (Loss) Per Share Basic earnings per share are computed by dividing net income (loss) available
to common stockholders by the weighted average number of common shares
outstanding for the period. The computation of diluted net income (loss) per
share reflects the potential dilution that could occur if securities or other
contracts to issue common stock were exercised or converted into common stock
or resulted in the issuance of common stock that would then share in the
earnings of Brigham. Year Ended December 31,2003
    
    
    2002
    
    
    2001Basic EPS:Income (loss) available to common stockholders
before cumulative change in accounting principle
    
    $
    14,574
    
    
    $
    (576
    )
    
    $
    9,238Cumulative change in accounting principle
    
    
    268
    
    
    
    
    
    
    
    Income (loss) available to common stockholders
    
    $
    14,842
    
    
    $
    (576
    )
    
    $
    9,238Common shares outstanding
    
    
    23,363
    
    
    
    16,138
    
    
    
    15,988Basic EPS:Income (loss) available to common stockholders
before cumulative change in accounting principle
    
    $
    0.63
    
    
    $
    (0.04
    )
    
    $
    0.58Cumulative change in accounting principle
    
    
    0.01
    
    
    
    
    
    
    
    Income (loss) available to common stockholders
    
    $
    0.64
    
    
    $
    (0.04
    )
    
    $
    0.58
     F-22




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##### Table of Contents



BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) Year Ended December 31,2003
    
    
    2002
    
    
    2001Diluted EPS:Income (loss) available to common stockholders before
cumulative change in accounting principle
    
    $
    14,574
    
    
    $
    (576
    )
    
    $
    9,238Cumulative change in accounting principle
    
    
    268
    
    
    
    
    
    
    
    Income (loss) available to common stockholders
    
    
    14,842
    
    
    
    (576
    )
    
    
    9,238Adjustments for assumed conversions:Interest on convertible debt
    
    
    
    
    
    
    
    
    
    
    826Dividends and accretion on mandatorily redeemable
preferred stock (1)
    
    
    3,290
    
    
    
    
    
    
    
    2,3643,290
    
    
    
    
    
    
    
    3,190Income (loss) available to common stockholders before
cumulative change in accounting principle - diluted
    
    
    17,864
    
    
    
    (576
    )
    
    
    12,428Cumulative change in accounting principle
    
    
    268
    
    
    
    
    
    
    
    Income (loss) available to common stockholders - diluted
    
    $
    18,132
    
    
    $
    (576
    )
    
    $
    12,428Common shares outstanding
    
    
    23,363
    
    
    
    16,138
    
    
    
    15,988Effect of dilutive securities:Convertible debt
    
    
    
    
    
    
    
    
    
    
    2,564Warrants
    
    
    317
    
    
    
    
    
    
    
    926Mandatorily redeemable preferred stock
    
    
    9,971
    
    
    
    
    
    
    
    8,426Stock options
    
    
    703
    
    
    
    
    
    
    
    301Potentially dilutive common shares
    
    
    10,991
    
    
    
    
    
    
    
    12,217Adjusted common shares outstanding - diluted
    
    
    34,354
    
    
    
    16,138
    
    
    
    28,205Diluted EPS:Income (loss) available to common stockholders before
cumulative change in accounting principle
    
    $
    0.52
    
    
    $
    (0.04
    )
    
    $
    0.44Cumulative change in accounting principle
    
    
    0.01
    
    
    
    
    
    
    
    Income (loss) available to common stockholders
    
    $
    0.53
    
    
    $
    (0.04
    )
    
    $
    0.44
  (1)
    
    The amount of dividends included in dividends and accretion on mandatorily redeemable preferred stock
includes only the dividends paid in kind on the $40 million of mandatorily redeemable preferred stock (2.0
million shares) that were issued with warrants whose exercise price is payable in either cash or in shares
of mandatorily redeemable preferred stock. At December 31, 2003, 2002, and 2001, potential dilution of approximately
1,000,000, 14,300,000 and 3,000,000 shares of common stock, respectively,
related to mandatorily redeemable preferred stock, convertible debt, warrants
and options were outstanding, but were not included in the computation of
diluted income (loss) per share because the effect of these instruments would
have been anti-dilutive. 11. Contingencies, Commitments and Factors Which May Affect Future Operations Litigation Brigham 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 Brigham. F-23




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##### Table of Contents



BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) On November 20, 2001, Brigham filed a lawsuit in the District Court of Travis
County, Texas, against Steve Massey Company, Inc. (Massey). The Petition claims Massey furnished defective casing
to Brigham, which ultimately led to the casing failure of the Palmer 347 #5
well and the loss of the Palmer #5 as a producing well. In 2004, the parties
agreed in principle to settle the case on terms favorable to Brigham. Brigham
will receive approximately $440,000 as a result of this settlement, which will
be a reduction to capitalized well costs. In addition, Massey has agreed to
drop its $445,819 counterclaim. On July 11, 2002, an employee of a contractor on Brighams Burkhart #1-R
location, Matagorda County, Texas, was involved in a fatal accident. The United

States Department of Labor Occupational Safety & Health Administration
conducted an inspection and, in October 2003, Brigham settled all issues
resulting from that inspection for $70,000. On October 8, 2002, relatives of the contractors employee filed a wrongful
death action in the district court for Matagorda County, Texas, against Brigham
and three of Brighams contractors in connection with his accidental death.
Plaintiffs were seeking unspecified actual and punitive damages. On March 23,
2004, a jury determined that Brigham had no liability in the accidental death
of the contractors employee. In September 2002, Brigham filed suit in the district court of Matagorda
County, Texas, against one of its contractors in connection with the drilling
of the Burkhart #1-R well. The suit claims that the contractor breached its
contract with Brigham and negligently performed services on the well, resulting
in damages of approximately $650,000. The contractor filed a counterclaim for
the recovery of approximately $315,000. The parties agreed in principle to
settle the case in February 2004. The settlement will result in a payment by
the contractor to Brigham and its co-participants. In addition, the contractor
will drop its counterclaim. Based on the amount of the settlement, the
additional costs that were covered by insurance, and the insurer being
subrogated to Brighams claim, Brigham will not receive any incremental
recovery as a result of the settlement. The operator of the Stonehocker #1 disputed Brighams ownership interest in the
well. In January 2004, the Oklahoma Corporation Commission ruled in favor of
Brigham. The operator of the Stonehocker #1 appealed the ruling and the
Oklahoma Corporation Commission affirmed its original ruling in March 2004. The
operator may now appeal the ruling to the Oklahoma Supreme Court. A company that relinquished its ownership interest in the Nold #1S well as a
result of a non-consent election in the re-completion of the well has asserted
that it did not relinquish its entire interest, but rather became subject only
to a 400 percent payout provision. In November 2003, the company filed a
lawsuit against Brigham for breach of contract. If the suit is successful, it
could result in a judgment of as much as $700,000. Brigham has not recorded a
contingent liability in connection with this suit. At this point in
time, Brigham cannot predict the outcome of this case. In December 2003, Brigham filed a lawsuit in the United States District Court
for the Western District of Texas against another company and a former employee
concerning the defendants misappropriation of Brighams trade secrets and
breach of confidentiality obligations. Defendants have denied any wrongdoing
and have asserted a counterclaim against Brigham for alleged tortuous
interference with an existing business relationship between the company and its
employee. The counterclaim does not specify the amount of damages claimed
other than that the damages exceed $75,000 (the jurisdictional limit). At this
point in time, Brigham cannot predict the outcome of this case. As of December 31, 2003, there are no known environmental or other regulatory
matters related to Brighams operations that are reasonably expected to result
in a material liability to Brigham. Compliance with environmental laws and
regulations has not had, and is not expected to have, a material adverse effect
on Brighams capital expenditures. F-24




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##### Table of Contents



BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) Operating Lease Commitments Brigham leases office equipment and space under operating leases expiring at
various dates. The noncancelable term of the lease for Brighams office space
expires in 2007 with an option to renew for an additional five years. The
future minimum annual rental payments under the noncancelable terms of these
leases at December 31, 2003 are as follows (in thousands): 2004
    
    $
    9102005
    
    
    9102006
    
    
    9102007
    
    
    455$
    3,185
 Future minimum rental payments are not reduced by sublease rental income of
approximately $64,000 due in 2004 and $38,000 due in 2005 under noncancelable
subleases. Rental expense for the years ended December 31, 2003, 2002 and 2001 was
approximately $851,000, $868,000 and $731,000, respectively. Major Purchasers The following purchasers accounted for 10% or more of Brighams oil and natural
gas sales for the years ended December 31, 2003, 2002 and 2001: 2003
    
    2002
    
    2001Purchaser A
    
    
    
    
    
    19
    %
    
    45
    %Purchaser B
    
    
    
    
    
    
    
    
    15
    %Purchaser C
    
    
    13
    %
    
    15
    %
    
    Purchaser D
    
    
    3
    %
    
    11
    %
    
    
 Brigham believes that the loss of any individual purchaser would not have a
long-term material adverse impact on its financial position or results of
operations. Factors Which May Affect Future Operations Since Brighams major products are commodities, significant changes in the
prices of oil and natural gas could have a significant impact on Brighams
results of operations for any particular year. 12. Derivative Instruments and Hedging Activities Brigham utilizes various commodity swap and option contracts to (i) reduce the
effects of volatility in price changes on the oil and natural gas commodities
it produces and sells, (ii) support its capital budgeting plans, and (iii)
lock-in prices to protect the economics related to certain capital projects. F-25




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##### Table of Contents



BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) The following table summarizes the hedging contracts to which Brigham was a
party at December 31, 2003, the total natural gas and crude oil production
volumes subject to those contacts and the weighted average NYMEX reference
price for those volumes: Swaps
    
    CollarsWeighted
    
    
    
    
    
    Weighted AverageAverage
    
    
    
    
    
    Floor
    
    CeilingNatural gas
    
    Volumes
    
    Price
    
    Volumes
    
    Price
    
    Price(MMbtu)
    
    ($/MMbtu)
    
    (MMbtu)
    
    ($/MMbtu)Quarter Ended:March 31, 2004
    
    
    295,750
    
    
    
    4.963
    
    
    
    546,000
    
    
    
    4.125
    
    
    
    8.433June 30, 2004
    
    
    227,500
    
    
    
    4.252
    
    
    
    409,500
    
    
    
    4.139
    
    
    
    5.389September 30, 2004
    
    
    138,000
    
    
    
    4.180
    
    
    
    299,000
    
    
    
    4.135
    
    
    
    5.350December 31, 2004.
    
    
    92,000
    
    
    
    4.360
    
    
    
    230,000
    
    
    
    4.150
    
    
    
    5.662March 31, 2005
    
    
    
    
    
    
    
    
    
    
    202,500
    
    
    
    4.139
    
    
    
    6.633June 30, 2005
    
    
    
    
    
    
    
    
    
    
    136,500
    
    
    
    4.083
    
    
    
    5.107
 Crude oil
    
    (Bbls)
    
    ($/Bbl)
    
    (Bbls)
    
    ($/Bbl)Quarter Ended:March 31, 2004
    
    
    29,575
    
    
    
    25.35
    
    
    
    45,500

    
    
    
    23.00
    
    
    
    30.43June 30, 2004
    
    
    20,475
    
    
    
    24.52
    
    
    
    31,850
    
    
    
    23.00
    
    
    
    28.92September 30, 2004
    
    
    13,800
    
    
    
    23.91
    
    
    
    18,400
    
    
    
    23.00
    
    
    
    27.00December 31, 2004.
    
    
    9,200
    
    
    
    23.80
    
    
    
    16,100
    
    
    
    23.00
    
    
    
    26.21March 31, 2005
    
    
    
    
    
    
    
    
    
    
    15,750
    
    
    
    23.00
    
    
    
    25.85June 30, 2005
    
    
    
    
    
    
    
    
    
    
    6,825
    
    
    
    23.00
    
    
    
    26.45
 The following table summarizes the hedging contracts to which Brigham entered
subsequent to December 31, 2003, the total natural gas and crude oil production
volumes subject to those contacts and the weighted average NYMEX reference
price for those volumes: CollarsWeighted AverageFloor
    
    CeilingNatural gas
    
    Volumes
    
    Price
    
    Price(MMbtu)
    
    ($/MMbtu)Quarter Ended:June 30, 2004
    
    
    101,100
    
    
    
    4.000
    
    
    
    6.830September 30, 2004
    
    
    101,200
    
    
    
    4.000
    
    
    
    6.830December 31, 2004.
    
    
    34,100
    
    
    
    4.000
    
    
    
    6.830
 Crude oil
    
    (Bbls)
    
    ($/Bbl)Quarter Ended:June 30, 2004
    
    
    18,200
    
    
    
    26.00
    
    
    
    33.55September 30, 2004
    
    
    18,400
    
    
    
    26.00
    
    
    
    33.55December 31, 2004.
    
    
    6,200
    
    
    
    26.00
    
    
    
    33.55
         F-26




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##### Table of Contents



BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) The fair value of hedging contracts is reflected on the balance sheet as
detailed in the following schedule. The current asset and liability amounts
represent the fair values expected to be included in the results of operations
for the subsequent year. December 31,2003
    
    2002Other current liabilities
    
    $
    2,140
    
    
    $
    3,168Other noncurrent liabilities
    
    
    40
    
    
    
    Other noncurrent assets
    
    
    3
    
    
    
    Accumulated other comprehensive income
    
    $
    2,177
    
    
    $
    3,168
 Brigham reports average oil and natural gas prices and revenues including the
net results of hedging activities. The following table sets forth Brighams oil
and natural gas prices including and excluding the hedging gains and losses and
the increase or decrease in oil and natural gas revenues as a result of the
hedging activities for the three year period ended December 31, 2003: Year Ended December 31,2003
    
    2002
    
    2001Natural gasAverage price per Mcf as reported (including hedging results)
    
    $
    4.92
    
    
    $
    3.21
    
    
    $
    3.11Average price per Mcf realized (excluding hedging results)
    
    $
    5.68
    
    
    $
    3.33
    
    
    $
    4.29Decrease in revenue (in thousands)
    
    $
    4,807
    
    
    $
    712
    
    
    $
    8,001OilAverage price per Bbl as reported (including hedging results)
    
    $
    28.17
    
    
    $
    23.55
    
    
    $
    24.05Average price per Bbl realized (excluding hedging results)
    
    $
    30.79
    
    
    $
    25.17
    
    
    $
    24.38Decrease in revenue (in thousands)
    
    $
    1,885
    
    
    $
    1,135
    
    
    $
    153
 Derivative instruments that do not qualify as hedging contracts are recorded at
fair value on the balance sheet. At each balance sheet date, the value of these
derivatives is adjusted to reflect current fair value and any gains or losses
are recognized as other income or expense. At December 31, 2003 and 2002, there
were no derivatives that did not qualify as hedging contracts. Brigham
recognized $0 million, $0.4 million and $9.7 million in non-cash gains related
to changes in the fair values of these derivative contracts and $0 million,
$0.6 million, and $1.5 million in losses related to the cash settlement
payments made by Brigham to the counterparty for the years ended December 31,
2003, 2002 and 2001, respectively. For the years ended December 31, 2003 and 2002, ineffectiveness associated with
Brighams derivative commodity instruments designated as cash flow hedges
decreased earnings by approximately $0.7 million and $0.1 million,
respectively. These amounts are included in other income and expense. There was
no ineffectiveness for the year ended December 31, 2001. Interest rate swap Periodically, Brigham may use interest rate swap contracts to adjust the
proportion of its total debt that is subject to variable interest rates. Under
such an interest rate swap contract, Brigham agrees to pay an amount equal to a
specified fixed-rate of interest for a certain notional amount and receive in
return an amount equal to a variable-rate. The notional amounts of the contract
are not exchanged. No other cash payments are made unless the contract is
terminated prior to maturity. Although no collateral is held or exchanged for
the contract, the interest rate swap contract is entered into with a major
financial institution in order to minimize Brighams counterparty credit risk.
The interest rate swap contract is designated as cash flow hedges against
changes in the amount of future cash flows associated with Brighams interest
payments on variable-rate debt. The effect of this accounting on operating
results is that interest expense on a portion of variable-rate debt being
hedged is recorded based on fixed interest rates. F-27




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##### Table of Contents



BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) At December 31, 2003, Brigham had an interest rate swap contract to pay a
fixed-rate of interest of 8.76% on $20 million notional amount of senior
subordinated notes. The $20 million notional amount of the outstanding
contract matures in March 2009. As of December 31, 2003, approximately $112,000
of unrealized losses are included in accumulated other comprehensive income
(loss) on the balance sheet which represents the fair values of the interest
rate swap agreement as of that date. The fair value of the interest rate swap
contract is based on quoted market prices and third-party provided
calculations, which reflect the present values of the difference between
estimated future variable-rate receipts and future fixed-rate payments. 13. Financial Instruments Brigham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-term
maturities. The carrying value of Brighams senior credit facility approximates
its fair market value since it bears interest at floating market interest
rates. The fair value of Brighams senior subordinated notes at December 31,
2003 and 2002 was $20.1 million and $24.0 million, respectively. The carrying
value of the Series A mandatorily redeemable preferred stock approximates its
fair market value because this is the amount that Brigham would be required to
pay to extinguish the preferred stock. Brighams accounts receivable relate to oil and natural gas sold to various
industry companies, and amounts due from industry participants for expenditures
made by Brigham on their behalf. Credit terms, typical of industry standards,
are of a short-term nature and Brigham does not require collateral. Brighams
accounts receivable at December 31, 2003 and 2002 do not represent significant
credit risks as they are dispersed across many counterparties. Counterparties
to the natural gas and crude oil price swaps are investment grade financial
institutions. 14. Employee Benefit Plans Brigham has adopted a defined contribution 401(k) plan for substantially all of
its employees. The plan provides for Brigham matching of employee contributions
to the plan, at Brighams discretion. During 2003, 2002 and 2001, Brigham
provided a base match equal to 25% of eligible employee contributions. Based on
attainment of performance goals established at the beginning of each fiscal
year, Brigham matched an additional 41%, 62.5% and 17% of eligible employee
contributions made during 2003, 2002 and 2001, respectively. Brigham
contributed $232,000, $260,000 and $102,000 to the 401(k) plan for the years
ended December 31, 2003, 2002 and 2001, respectively, to match eligible
contributions by employees. 15. Stock Based Compensation Brigham provides an incentive plan for the issuance of stock options, stock
appreciation rights, stock, restricted stock, cash or any combination of the
foregoing. The objective of this plan is to provide incentive and reward key
employees whose performance may have a significant impact on the success of
Brigham. As amended by stockholder resolution in May 2003, the number of shares
available under the plan is equal to the lesser of 4,387,500 or 15% of the
total number of shares of common stock outstanding. The Compensation Committee
of the Board of Directors determines the type of awards made to each
participant and the terms, conditions and limitations applicable to each award.
At December 31, 2002, Brigham had issued approximately 85,000 incentive awards
in excess of the amount then currently authorized by the plan. Brigham
stockholders approved an increase in the total shares available for incentive
awards as noted above in May 2003. As a result, the grant date for the 85,000
options is considered May 2003 for accounting purposes. The exercise price for
these options was originally set at the market value of Brighams common stock,
however as of May 2003, it was less than the fair market value of Brighams
common stock at that date. Accordingly, Brigham recognized approximately
$156,000 of unearned stock compensation and is amortizing this amount to
compensation expense over the vesting period of the options. With the exception
of these 85,000 options, options granted subsequent to March 4, 1997 have an
exercise price equal to the fair market value of Brighams common stock on the
date of grant and generally vest over three to five years. F-28




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##### Table of Contents



BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) In May 2002, Brigham accelerated the vesting of a certain departing employees
stock options and extended the time limitation for exercising that employees
stock options following termination of employment. These revisions resulted in
the immediate recognition of stock compensation cost as measured at the
effective date of the changes. Accordingly, a non-cash charge to general and
administrative expense in the amount of $596,000 was recorded. Brigham also maintains a director stock option plan under which stock options
are awarded to non-employee directors. In May 2003, the plan was amended by
stockholder resolution to increase the number of shares available for issuance
to 430,000 shares of common stock. Options granted under this plan have an
exercise price equal to the fair market value of Brigham common stock on the
date of grant and generally vest over five years. The following table summarizes activity under the incentive plans for each of
the three years ended December 31, 2003: Weighted-AverageShares
    
    
    Exercise PriceOptions outstanding December 31, 2000
    
    
    1,407,114
    
    
    $
    2.89Options granted
    
    
    546,500
    
    
    
    3.44Options forfeited or cancelled
    
    
    (239,369
    )
    
    
    (3.48
    )Options exercised
    
    
    (97,474
    )
    
    
    (2.59
    )Options outstanding December 31, 2001
    
    
    1,616,771
    
    
    
    3.00Options granted
    
    
    481,000
    
    
    
    4.12Options forfeited or cancelled
    
    
    (177,129
    )
    
    
    (3.25
    )Options exercised
    
    
    (132,507
    )
    
    
    (2.23
    )Options outstanding December 31, 2002
    
    
    1,788,135
    
    
    
    3.00Options granted
    
    
    1,127,500
    
    
    
    6.46Options forfeited or cancelled
    
    
    (23,200
    )
    
    
    (3.49
    )Options exercised
    
    
    (309,760
    )
    
    
    (2.68
    )Options outstanding December 31, 2003
    
    
    2,582,675
    
    
    $
    4.78
 Brigham is required to use variable accounting for 252,500 of the stock options
granted during 2000 of which 217,000 remain outstanding at December 31, 2003.
This method of accounting requires recognition of noncash compensation expense
for the difference between the option exercise price and the market price of
Brighams stock at the end of the accounting period of vested options. Since
the market price for Brighams stock is a component of the variable cost
accounting calculation, it is not possible to determine the total noncash
compensation expense that will be recognized during the vesting period of these
options. The following table summarizes information about stock options outstanding at
December 31, 2003: Options Outstanding
    
    
    Options ExercisableNumber
    
    
    Weighted-
    
    
    
    
    
    
    NumberOutstanding at
    
    
    Average
    
    
    Weighted-
    
    
    Exercisable at
    
    
    Weighted-December 31,
    
    
    Remaining
    
    
    Average
    
    
    December 31,
    
    
    AverageExercise Price
    
    2003
    
    
    Contractual Life
    
    
    Exercise Price
    
    
    2003
    
    
    Exercise Price$  1.55
to $ 1.83
    
    
    169,500
    
    
    3.1 years
    
    
    $
    1.83
    
    
    
    131,200
    
    
    $
    1.832.38
to    3.41
    
    
    588,925
    
    
    4.4 years
    
    
    
    3.16
    
    
    
    269,483
    
    
    
    2.933.61
to    5.19
    
    
    802,250
    
    
    5.0 years
    
    
    
    4.08
    
    
    
    243,950
    
    
    
    3.956.31
to  14.38
    
    
    1,022,000
    
    
    6.7 years
    
    
    
    6.75
    
    
    
    12,000
    
    
    
    6.98$ 1.55 to $14.38
    
    
    2,582,675
    
    
    5.4 years
    
    
    $
    4.78
    
    
    
    656,633
    
    
    $
    3.14
     F-29




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##### Table of Contents



BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) Restricted Stock During the year ended December 31, 2003, Brigham issued 350,000 restricted
shares of common stock as compensation to officers and key employees of
Brigham. The restricted shares vest over five years. Brigham recognized
approximately $1.8 million of unearned stock compensation and will amortize
this amount to compensation expense over the vesting period of the restricted
stock. The following table reflects the outstanding restricted stock awards
and activity related thereto for the year ended December 31, 2003: Year Ended December 31,2003Weighted-Number of
    
    AverageShares
    
    
    PriceRestricted Stock Awards:Shares granted
    
    
    350,000
    
    
    $
    5.23Lapse of restrictions
    
    
    
    
    
    
    Restricted shares outstanding at the end of the year
    
    
    350,000
    
    
    $
    5.23
 16. Related Party Transactions During the years ended December 31, 2003, 2002, and 2001, Brigham incurred
costs of approximately $2.0 million, $1.1 million and $0.4 million,
respectively, in fees for land acquisition services performed by a company
owned by a brother of Brighams Chairman, President and Chief Executive Officer
and its Executive Vice PresidentLand and Administration. Other participants in
Brighams 3-D seismic projects reimbursed Brigham for a portion of these
amounts. At December 31, 2003 and 2002, Brigham had recorded a liability in
accounts payable of approximately $262,000 and $0, respectively, related to
services performed by this company. Mr. Harold Carter, a director of Brigham, served as a consultant to Brigham on
various aspects of its business and strategic issues. Fees paid for these
services by Brigham were approximately $30,000, $45,000, and $44,000 for the
years ended December 31, 2003, 2002, and 2001, respectively. Additional
disbursements totaling approximately $12,000, $12,000, and $6,000 were made
during 2003, 2002, and 2001, respectively, for the reimbursement of certain
expenses. At December 31, 2003 and 2002, there were no payables related to
these services recorded by Brigham. At December 31, 2003 and 2002 Brigham had short-term accounts receivable from
Mr. Steven Webster, a director of Brigham, of approximately $8,300 and $94,000,
respectively. These receivables represent the directors share of costs related
to his working interest ownership in the Staubach #1, Burkhart #1R and
Matthes-Huebner #1 wells that are operated by Brigham. Mr. Webster obtained his
interest in these wells through an exploration and production company that is
not affiliated with Brigham. On March 1, 2002, Brigham ended an agreement to sell substantially all of its
crude production to a single company, and began utilizing a broader range of
purchasers. In April 2002, Brigham began selling a portion of its oil
production to Citation Crude Marketing, Inc. based on an evaluation of terms
and capabilities offered by several companies. Brighams Executive Vice
President and Chief Financial Officer and board member through July 12, 2002 is
the brother of the President of Citation Crude Marketing, Inc., and the son of
the President and Chief Executive Officer of Citation Oil & Gas Corporation.
Brigham sold Citation Crude Marketing, Inc. approximately 49,000 barrels of oil
with a value of $1.6 million during 2003 and 212,000 barrels of oil with a
value of $5.6 million to during 2002. From time to time, in the normal course of business, Brigham has engaged a
drilling company in which Mr. Steven Webster, one of Brighams current
directors, owns stock and serves on the board of directors. Total payments to
the drilling company during 2003 and 2002 were $1.2 million and $0.4 million,
respectively. At December 31, 2003, Brigham owed the drilling company
approximately $0.3 million. At December 31, 2002, Brigham owed the drilling
company approximately $0.4 million. F-30




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##### Table of Contents



BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) From time to time, in the normal course of business, Brigham has engaged a
service company in which Mr. Hobart Smith, one of Brighams current directors,
owns stock and serves as a consultant. Total payments to the service company
during 2003 and 2002 were $478,000 and $130,000, respectively. At December 31,
2003 and 2002, Brigham owed the service company approximately $237,000 and
$76,000, respectively. In October 2001, Brigham entered into a Joint Exploration Agreement with
Carrizo Oil & Gas, Inc. (Carrizo). Under the terms of this agreement the
parties: (1) blended their existing oil and gas leasehold positions covering a
South Texas prospect; (2) identified five separate areas of mutual interest
within the prospect; and (3) agreed upon procedures for the future exploration
and development of the prospect. In November and December of 2002, Brigham and
Carrizo entered into agreements that increased Brighams interest in some of
the leasehold within the South Texas prospect. Mr. Steven Webster, one of
Brighams current directors, was a co-founder of Carrizo and is currently
chairman of Carrizos board of directors. At December 31, 2003 and 2002,
Brigham was owed $206,000 and $413,000, respectively, by Carrizo for
exploration and production activities. Brigham owed Carrizo $50,000 and $11,000
at December 31, 2003 and 2002, respectively. During 2001, Brigham entered into three agreements with Aspect Resources, LLC
(Aspect). These agreements included: (1) a Joint Development Agreement
extending the term of an area of mutual interest arrangement, and establishing
cost sharing for potential expenditures within the project area; (2) an
Agreement and Partial Assignment of Seismic Participation Agreement under which
Aspect assigned Brigham an interest in an existing 3-D seismic project and
Brigham must pay the assigned interest portion of future costs; and (3) a
Geophysical Exploration Agreement under which Brigham assigned Aspect an
interest in an existing 3-D project area (with certain exclusion) and Aspect
agreed to provide certain seismic data overlapping the project area and share
in future costs. The President of Aspect was a director of Brigham and a member
of the Compensation Committee for a portion of 2002 and all of 2001. Total
amounts paid to Aspect during 2003 and 2002 for exploration, development and
production operations were $0 and $189,000, respectively. Total amounts paid to
Brigham by Aspect, or on their behalf, during 2003 and 2002 for exploration,
development and production operations were $91,000 and $1,008,000,
respectively. There were no amounts owed by Brigham to Aspect at December 31,
2003 or 2002. Aspect owed Brigham $69,000 and $312,000 at December 31, 2003 and
2002, respectively, for various oil and gas exploration and production
activities. Brigham was also owed $2,800 by Aspect Management Corp., an
affiliate of Aspect, at December 31, 2002 for joint venture operations. 17. Supplemental Cash Flow Information Year Ended December 31,2003
    
    2002
    
    2001Cash paid for interest
    
    $
    2,447
    
    
    $
    3,974
    
    
    $
    4,257Noncash investing and financing activities:Increase in current liabilities for deferred loan fees to be paid in future
    
    
    
    
    
    
    
    
    
    
    200Dividends and accretion on mandatorily redeemable preferred stock
    
    
    3,448
    
    
    
    2,952
    
    
    
    2,450Conversion of senior credit facility to common stock
    
    
    
    
    
    
    10,000
    
    
    
    Conversion of preferred stock to common stock via exercise of warrants
    
    
    18,534
    
    
    
    
    
    
    
    Issuance of restricted stock
    
    
    1,831
    
    
    
    
    
    
    
    Issuance of stock options
    
    
    296
    
    
    
    
    
    
    
    
                F-31




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##### Table of Contents



BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) 18. Other Assets and Liabilities Other current assets consist of the following (in thousands): December 31,2003
    
    
    2002Gas imbalance receivables
    
    $
    2,477
    
    
    $
    3,656Deposits
    
    
    
    
    
    
    1,909Other
    
    
    1,129
    
    
    
    1,078$
    3,606
    
    
    $
    6,643
 Deposits are amounts held by Brighams derivative counterparty. Other current liabilities consist of the following (in thousands): December 312003
    
    
    2002Gas imbalance liabilities
    
    $
    2,064
    
    
    $
    5,650Derivative liabilities
    
    
    2,141
    
    
    
    3,168Other
    
    
    1,193
    
    
    
    1,516$
    5,398
    
    
    $
    10,334
 19. Oil and Natural Gas Exploration and Production Activities Oil and natural gas sales reflect the market prices of net production sold or
transferred with appropriate adjustments for royalties, net profits interest
and other contractual provisions. Lease operating expenses include lifting
costs incurred to operate and maintain productive wells and related equipment
including such costs as operating labor, repairs and maintenance, materials,
supplies and fuel consumed. Production taxes include production and severance
taxes. Depletion of oil and natural gas 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 oil and natural gas acquisition, exploration and
development activities follow (in thousands): December 31,2003
    
    
    2002
    
    
    2001Costs incurred for the year:Exploration
    
    $
    20,732
    
    
    $
    12,693
    
    
    $
    18,210Property acquisition
    
    
    5,037
    
    
    
    3,213
    
    
    
    3,437Development
    
    
    22,285
    
    
    
    13,301
    
    
    
    14,353Proceeds from participants
    
    
    (793
    )
    
    
    (703
    )
    
    
    (135
    )$
    47,261
    
    
    $
    28,504
    
    
    $
    35,865
 Costs incurred represent amounts incurred by Brigham for exploration, property
acquisition and development activities. Periodically, Brigham will receive
proceeds from participants subsequent to project initiation for an assignment
of an interest in the project. These payments are represented by Proceeds from
participants in the table above. F-32




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##### Table of Contents



BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) Following is a summary of capitalized costs (in thousands) excluded from
depletion at December 31, 2003 by year incurred. At this time, Brigham is
unable to predict either the timing of the inclusion of these costs and the
related natural gas and oil reserves in its depletion computation or their
potential future impact on depletion rates. December 31,
    
    
    Prior2003
    
    
    2002
    
    
    2001
    
    
    Years
    
    
    TotalProperty acquisition
    
    $
    2,624
    
    
    $
    627
    
    
    $
    1,468
    
    
    $
    8,957
    
    
    $
    13,676Exploration
    
    
    2,570
    
    
    
    935
    
    
    
    112
    
    
    
    18,348
    
    
    
    21,965Capitalized interest
    
    
    503
    
    
    
    527
    
    
    
    1,021
    
    
    
    814
    
    
    
    2,865Total
    
    $
    5,697
    
    
    $
    2,089
    
    
    $
    2,601
    
    
    $
    28,119
    
    
    $
    38,506
 20. Oil and Natural Gas Reserves and Related Financial Data (unaudited) Information with respect to Brighams oil and natural gas 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 Brighams independent petroleum consultants and internal
petroleum reservoir engineers. Oil and Natural Gas Reserve Data The following tables present Brighams estimates of its proved oil and natural
gas reserves. Brigham emphasizes reserves are approximates and are expected to
change as additional information becomes available. Reservoir engineering is a
subjective process of estimating underground accumulations of oil and natural
gas that cannot be measured in an exact way, and the accuracy of any reserve
estimate is a function of the quality of available data and of engineering and
geological interpretation and judgment. A substantial portion of the reserve
balances was estimated utilizing the volumetric method, as opposed to the
production performance method. NaturalGas
    
    
    Oil(MMcf)
    
    
    (MBbls)Proved reserves at December 31, 2000
    
    
    78,167
    
    
    
    2,870Revisions of previous estimates
    
    
    (1,959
    )
    
    
    351Extensions, discoveries and other additions
    
    
    22,554
    
    
    
    1,101Sales of minerals-in-place
    
    
    (3,402
    )
    
    
    (106
    )Production
    
    
    (6,766
    )
    
    
    (468
    )Proved reserves at December 31, 2001
    
    
    88,594
    
    
    
    3,748Revisions of previous estimates
    
    
    (824
    )
    
    
    (31
    )Extensions, discoveries and other additions
    
    
    18,005
    
    
    
    599Sales of minerals-in-place
    
    
    (556
    )
    
    
    (8
    )Production
    
    
    (5,791
    )
    
    
    (701
    )Proved reserves at December 31, 2002
    
    
    99,428
    
    
    
    3,607Revisions of previous estimates
    
    
    (6,148
    )
    
    
    176Extensions, discoveries and other additions
    
    
    22,479
    
    
    
    1,067Production
    
    
    (6,356
    )
    
    
    (720
    )Proved reserves at December 31, 2003
    
    
    109,403
    
    
    
    4,130Proved developed reserves at December 31:2000
    
    
    39,271
    
    
    
    1,8022001
    
    
    38,633
    
    
    
    2,6092002
    
    
    42,161
    
    
    
    2,3302003
    
    
    49,920
    
    
    
    2,863
     F-33




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##### Table of Contents



BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) Proved reserves are estimated quantities of natural gas and crude oil, which
geological and engineering data indicate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are proved reserves that can be
expected to be recovered through existing wells with existing equipment and
operating methods. Standardized Measure of Discounted Future Net Cash Inflows and Changes
Therein The following table presents a standardized measure of discounted future net
cash inflows (in thousands) relating to proved oil and natural gas reserves.
Future cash flows were computed by applying year-end prices of oil and natural
gas relating to Brigham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 oil and natural gas 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 Brighams oil and natural gas reserves. December 31,2003
    
    
    2002
    
    
    2001Future cash inflows
    
    $
    737,544
    
    
    $
    601,081
    
    
    $
    301,201Future production costs
    
    
    (123,176
    )
    
    
    (82,689
    )
    
    
    (47,430
    )Future development costs
    
    
    (58,978
    )
    
    
    (48,668
    )
    
    
    (36,983
    )Future income tax expense
    
    
    (138,118
    )
    
    
    (104,724
    )
    
    
    (34,062
    )Future net cash inflows
    
    
    417,272
    
    
    
    365,000
    
    
    
    182,72610% annual discount for estimated timing of cash flows
    
    
    (155,674
    )
    
    
    (125,302
    )
    
    
    (61,802
    )Standardized measure of discounted future net cash flows
    
    $
    261,598
    
    
    $
    239,698
    
    
    $
    120,924
 The base sales prices for Brighams reserve estimates were as follows: NaturalGas
    
    
    Oil(MMbtu)
    
    
    (Bbl)December 31, 2003
    
    $
    5.83
    
    
    $
    32.55December 31, 2002
    
    
    4.74
    
    
    
    31.25December 31, 2001
    
    
    2.57
    
    
    
    19.84
 These base prices were adjusted to reflect applicable transportation and
quality differentials on a well-by-well basis to arrive at realized sales
prices used to estimate Brighams reserves at these dates. F-34




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##### Table of Contents



BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) Changes in the future net cash inflows discounted at 10% per annum follow (in
thousands): December 31,2003
    
    
    2002
    
    
    2001Beginning of period
    
    $
    239,698
    
    
    $
    120,924
    
    
    $
    359,228Sales of oil and natural gas produced, net of production costs
    
    
    (51,126
    )
    
    
    (31,475
    )
    
    
    (27,296
    )Development costs incurred
    
    
    14,370
    
    
    
    8,625
    
    
    
    8,310Extensions and discoveries
    
    
    91,383
    
    
    
    60,872
    
    
    
    41,278Sales of minerals-in-place
    
    
    
    
    
    
    (1,064
    )
    
    
    (22,476
    )Net change of prices and production costs
    
    
    20,822
    
    
    
    136,808
    
    
    
    (322,047
    )Change in future development costs
    
    
    11,281
    
    
    
    (8,000
    )
    
    
    (15,956
    )Changes in production rates and other
    
    
    (65,967
    )
    
    
    (17,003
    )
    
    
    (29,545
    )Revisions of quantity estimates
    
    
    (15,063
    )
    
    
    (2,876
    )
    
    
    (22,676
    )Accretion of discount
    
    
    30,737
    
    
    
    14,681
    
    
    
    49,766Change in income taxes
    
    
    (14,537
    )
    
    
    (41,794
    )
    
    
    102,338End of period
    
    $
    261,598
    
    
    $
    239,698
    
    
    $
    120,924
 21. Quarterly Financial Data (Unaudited) Year Ended December 31, 2003Quarter 1
    
    
    Quarter 2
    
    
    Quarter 3
    
    
    Quarter 4Revenue
    
    $
    14,677
    
    
    $
    12,170
    
    
    $
    13,213
    
    
    $
    11,617Operating income
    
    
    7,393
    
    
    
    4,911
    
    
    
    5,590
    
    
    
    3,863Net income:Income available to common stockholders before
cumulative effect of change in accounting principle
    
    
    5,248
    
    
    
    2,385
    
    
    
    3,343
    
    
    
    3,598Cumulative effect of change in accounting principle
    
    
    268
    
    
    
    
    
    
    
    
    
    
    
    Net income available to common stockholders
    
    $
    5,516
    
    
    $
    2,385
    
    
    $
    3,343
    
    
    $
    3,598Net income per share:Basic:Income available to common stockholders before
cumulative effect of change in accounting principle.
    
    $
    0.27
    
    
    $
    0.12
    
    
    $
    0.16
    
    
    $
    0.11Cumulative effect of change in accounting principle.
    
    
    0.01
    
    
    
    
    
    
    
    
    
    
    
    Net income available to common stockholders
    
    $
    0.28
    
    
    $
    0.12
    
    
    $
    0.16
    
    
    $
    0.11Diluted:Income available to common stockholders before
cumulative effect of change in accounting principle.
    
    $
    0.19
    
    
    $
    0.10
    
    
    $
    0.13
    
    
    $
    0.10Cumulative effect of change in accounting principle.
    
    
    0.01
    
    
    
    
    
    
    
    
    
    
    
    Net income available to common stockholders
    
    $
    0.20
    
    
    $
    0.10
    
    
    $
    0.13
    
    
    $
    0.10
         F-35




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##### Table of Contents



BRIGHAM EXPLORATION COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued) Year Ended December 31, 2002Quarter 1
    
    
    Quarter 2
    
    
    Quarter 3
    
    
    Quarter 4Revenue
    
    $
    6,444
    
    
    $
    8,786
    
    
    $
    9,449
    
    
    $
    10,497Operating income
    
    
    1,016
    
    
    
    2,278
    
    
    
    3,424
    
    
    
    2,717Net income (loss) available to common stockholders
    
    
    (1,332
    )
    
    
    61
    
    
    
    989
    
    
    
    (294
    )Net income (loss) per share:Basic
    
    $
    (0.08
    )
    
    $
    0.00
    
    
    $
    0.06
    
    
    $
    (0.02
    )Diluted
    
    
    (0.08
    )
    
    
    0.00
    
    
    
    0.06
    
    
    
    (0.02
    )
                                     F-36




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##### Table of Contents



INDEX TO EXHIBITS Number
    
    
    
    Description3.1
    
    
    
    Certificate of Incorporation (filed as Exhibit 3.1 to Brighams Registration Statement on Form S-1
(Registration No. 333-22491), and incorporated herein by reference).3.2
    
    
    
    Certificates of Amendment to Certificate of Incorporation (filed as Exhibit 3.1.1 to Brighams
Registration Statement on Form S-3 (Registration No. 333-37558), and incorporated herein by
reference).3.3
    
    
    
    Bylaws (filed as Exhibit 3.2 to Brighams Registration Statement on Form S-1 (Registration No.
333-22491), and incorporated herein by reference).4.1
    
    
    
    Form of Common Stock Certificate (filed as Exhibit 4.1 to Brighams Registration Statement on Form S-1
(Registration No. 333-22491), and incorporated herein by reference).4.2
    
    
    
    Certificate of Designations of Series A Preferred Stock (Par Value $.01 Per Share) of Brigham
Exploration Company filed October 31, 2000 (filed as Exhibit 4.1 to Brighams Current Report on Form
8-K, as amended (filed November 8, 2000), and incorporated herein by reference).4.3
    
    
    
    Certificate of Amendment of Certificate of Designations of Series A Preferred Stock (Par Value $.01
Per Share) of Brigham Exploration Company, filed March 2, 2001 (filed as Exhibit 4.2.1 to Brighams
Annual Report on Form 10-K for the year ended December 31, 2000 (filed March 23, 2001), and
incorporated herein by reference).4.4
    
    
    
    Certificate of Designations of Series B Preferred Stock (Par Value $.01 Per Share) of Brigham
Exploration Company filed December 20, 2002 (filed as Exhibit 4.4 to Brighams Annual Report on Form
10-K for the year ended December 31, 2002 (filed March 31, 2003) and incorporated herein by
reference).10.1
    
    
    
    Amended and Restated Agreement of Limited Partnership of Brigham Oil & Gas, L.P., dated December 30,
1997 by and among Brigham, Inc., Brigham Holdings I, L.L.C. and Brigham Holdings II, L.L.C. (filed as
Exhibit 10.1.4 to Brighams Annual Report on Form 10-K for the year ended December 31, 1998, and
incorporated herein by reference)10.2*
    
    
    
    Consulting Agreement dated May 1, 1997, by and between Brigham Oil & Gas, L.P. and Harold D. Carter
(filed as Exhibit 10.4 to Brighams Registration Statement on Form S-1 (Registration No. 33-53873),
and incorporated herein by reference).10.3*
    
    
    
    Letter agreement, dated as of March 20, 2000, setting forth amendments effective January 1, 2000, to
the Consulting Agreement, dated May 1, 1997, by and between Brigham Oil & Gas, L.P. and Harold D.
Carter (filed as Exhibit 10.5.1 to Brighams Annual Report on Form 10-K for the year ended December
31, 1999, and incorporated herein by reference).10.4*
    
    
    
    Letter agreement, setting forth amendments to the Consulting Agreement, dated May 1, 1997, by and
between Brigham Oil & Gas, L.P. and Harold D. Carter.10.5*
    
    
    
    Employment Agreement, by and between Brigham Exploration Company and Ben M. Brigham (filed as Exhibit
10.7 to Brighams Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated
herein by reference).10.6*
    
    
    
    1997 Incentive Plan of Brigham Exploration Company as amended through April 9, 2003 (filed as Appendix
B to Brighams Definitive Proxy Statement on Schedule 14-A on May 7, 2003 and incorporated herein by
reference).10.7*
    
    
    
    Form of Option Agreement for certain executive officers (filed as Exhibit 10.9.1 to Brighams
Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by
reference).10.8*
    
    
    
    Form of Restricted Stock Agreement for certain executive officers dated as of October 27, 2000 (filed
as Exhibit 10.8.2 to Brighams Annual Report on Form 10-K for the year ended December 31, 2000 (filed
March 23, 2001), and incorporated herein by reference).10.9
    
    
    
    Two Bridgepoint Lease Agreement dated September 30, 1996, by and between Investors Life Insurance
Company of North America and Brigham Oil & Gas, L.P. (filed as Exhibit 10.14 to Brighams Registration
Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference).10.10
    
    
    
    First Amendment to Two Bridge Point Lease Agreement dated April 11, 1997 between Investors Life
Insurance Company of North America and Brigham Oil & Gas, L.P. (filed as Exhibit 10.9.1 to Brighams
Registration Statement on Form S-1 (Registration No. 333-53873), and incorporated herein by
reference).10.11
    
    
    
    Second Amendment to Two Bridge Point Lease Agreement dated October 13, 1997 between Investors Life
Insurance Company of North America and Brigham Oil & Gas, L.P. (filed as Exhibit 10.9.2 to Brighams
Registration Statement on Form S-1 (Registration No. 333-53873), and incorporated herein by
reference).10.12
    
    
    
    Letter dated April 17, 1998 exercising Right of First Refusal to Lease 3rd Option Space (filed as
Exhibit 10.9.3 to Brighams Registration Statement on Form S-1 (Registration No. 333-53873), and
incorporated herein by reference).




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##### Table of Contents



Number
    
    
    
    Description10.13
    
    
    
    Form of Indemnity Agreement between the Registrant and each of its executive officers (filed as
Exhibit 10.28 to Brighams Registration Statement on Form S-1 (Registration No. 333-22491), and
incorporated herein by reference).10.14
    
    
    
    Registration Rights Agreement dated February 26, 1997 by and among Brigham Exploration Company,
General Atlantic Partners III L.P., GAP-Brigham Partners, L.P., RIMCO Partners, L.P. II, RIMCO
Partners L.P. III, and RIMCO Partners, L.P. IV, Ben M. Brigham, Anne L. Brigham, Harold D. Carter,
Craig M. Fleming, David T. Brigham and Jon L. Glass (filed as Exhibit 10.29 to Brighams Registration
Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference).10.15* 
    
    
    
    1997 Director Stock Option Plan, as amended as of April 9, 2003.10.16
    
    
    
    Form of Employee Stock Ownership Agreement (filed as Exhibit 10.31 to Brighams Registration Statement
on Form S-1 (Registration No. 333-22491), and incorporated herein by reference).10.17
    
    
    
    Agreement and Assignment of Interest in Geophysical Exploration Agreement, Esperson Dome Project,
dated November 1, 1994, by and between Brigham Oil & Gas, L.P. and Vaquero Gas Company (filed as
Exhibit 10.33 to Brighams Registration Statement on Form S-1 (Registration No. 333-22491), and
incorporated herein by reference).10.18
    
    
    
    Agreement and Partial Termination of Agreement and Assignment of Interest in Geophysical Exploration
Agreement, Esperson Dome Project dated March 14, 2003, by and between Brigham Oil & Gas, L.P. and
Vaquero Gas Company, Incorporated (filed as Exhibit 10.53 to Brighams Quarterly Report on Form 10-Q
for the quarter ended June 30, 2003 and incorporated herein by reference)10.19
    
    
    
    Proposed Trade Structure, RIMCO/Tigre Project, Vermillion Parish, Louisiana, among Brigham Oil & Gas,
L.P., Tigre Energy Corporation and Resource Investors Management Company (filed as Exhibit 10.36 to
Brighams Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by
reference).10.20
    
    
    
    Letter relating to Proposed Trade Structure, RIMCO/Tigre Project, dated January 31, 1997, from
Resource Investors Management Company to Brigham Oil & Gas, L.P. (filed as Exhibit 10.36 to Brighams
Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by
reference).10.21
    
    
    
    Agreement dated March 6, 2000 by and between RIMCO Production Co., Tigre Energy Corporation and
Brigham Oil & Gas, L.P. regarding modifications to the Proposed Trade Structure, RIMCO/Tigre Project,
dated January 31, 1997.10.22
    
    
    
    Form Change of Control Agreement dated as of September 20, 1999 between Brigham Exploration Company
and certain Officers (filed as Exhibit 10.3 to Brighams Quarterly Report on Form 10-Q for the fiscal
quarter ended September 30, 1999 and incorporated by reference herein).10.23
    
    
    
    Joint Development Agreement, dated as of February 10, 1999, by and between Brigham Oil & Gas, L.P. and
Aspect Resources LLC. (filed as Exhibit 10.65 to Brighams Annual Report on Form 10-K for the year
ended December 31, 1999, and incorporated herein by reference).10.24
    
    
    
    First Amendment, dated as of May 10, 1999, to that certain Joint Development Agreement entered into
effective as of February 10, 1999, by and between Brigham Oil & Gas, L.P. and Aspect Resources LLC.
(filed as Exhibit 10.65.1 to Brighams Annual Report on Form 10-K for the year ended December 31,
1999, and incorporated herein by reference).10.25
    
    
    
    Acquisition and Participation Agreement dated October 21, 1999, by and between Brigham Oil & Gas, L.P.
and Aspect Resources LLC. (filed as Exhibit 10.65.2 to Brighams Annual Report on Form 10-K for the
year ended December 31, 1999, and incorporated herein by reference).10.26
    
    
    
    Letter agreement, dated as of December 30, 1999, regarding amendments to Joint Development Agreement,
dated as of February 10, 1999, as amended, by and between Brigham Oil & Gas, L.P. and Aspect Resources
LLC. (filed as Exhibit 10.65.3 to Brighams Annual Report on Form 10-K for the year ended December 31,
1999, and incorporated herein by reference).10.27
    
    
    
    Letter agreement dated as of September 6, 1999 between Brigham Oil & Gas, L.P. and Brigham Land
Management Company, Inc. regarding work to be performed within Brighams Angelton Project. (filed as
Exhibit 10.66 to Brighams Annual Report on Form 10-K for the year ended December 31, 1999, and
incorporated herein by reference).10.28
    
    
    
    Registration Rights Agreement dated November 1, 2000 by and between Brigham Exploration Company, DLJ
MB Funding III, Inc., and DLJ ESC II, LP. (filed as Exhibit 10.10 to Brighams Current Report on Form
8-K, as amended (filed November 8, 2000), and incorporated herein by reference).




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##### Table of Contents



Number
    
    
    
    Description10.29
    
    
    
    First Amendment to Registration Rights Agreement, dated March 5, 2001, by and among Brigham
Exploration Company, DLJMB Funding III, Inc., DLJ Merchant Banking Partners III, LP, DLJ ESC II, LP
and DLJ Offshore Partners III, CV (filed as Exhibit 10.71 to Brighams Annual Report on Form 10-K for
the year ended December 31, 2000 (filed March 23, 2001), and incorporated herein by reference).10.30
    
    
    
    Exchange Agreement, dated November 21, 2002 between Brigham Exploration Company, Brigham Oil & Gas,
L.P. and Shell Capital Inc.10.31
    
    
    
    Omnibus Agreement dated November 21, 2002 between Brigham Exploration Company, Brigham Oil & Gas, L.P.
and certain Credit Suisse First Boston entities.10.32
    
    
    
    Securities Purchase Agreement dated December 20, 2002 between Brigham Exploration Company and certain
Credit Suisse First Boston Entities.10.33
    
    
    
    Registration Rights Agreement dated December 20, 2002 between Brigham Exploration Company and Shell
Capital Inc.10.34
    
    
    
    Second Amendment to Registration Rights Agreement dated December 21, 2002 between Brigham Exploration
Company and Credit Suisse First Boston Entities.10.35
    
    
    
    Stockholders Voting Agreement dated December 20, 2002 between Brigham Exploration Company, certain
Credit Suisse First Boston entities, Ben M. and Anne L. Brigham, Harold D. Carter, General Atlantic
Partners, III, L.P., GAP-Brigham Partners, L.P. GAP Co Investment Partners II, L.P., Aspect Resources,
LLC and certain officers.10.36
    
    
    
    Second Amended and Restated Credit Agreement, dated March 21, 2003 between Brigham Oil & Gas, L.P.,
Société Générale, Societe Generale, The Royal Bank of Scotland plc and Bank of America, N.A.10.37
    
    
    
    Amended and Restated Subordinated Credit Agreement, dated March 21, 2003 between Brigham Oil & Gas,
L.P., and The Royal Bank of Scotland plc.10.38 
    
    
    
    First Amendment to Amended and Restated Subordinated Credit Agreement dated March 21, 2003 between
Brigham Oil & Gas, L.P., and The Royal Bank of Scotland plc.21 
    
    
    
    Subsidiaries of the Registrant.23.1 
    
    
    
    Consent of PricewaterhouseCoopers LLP, independent public accountants.31.1 
    
    
    
    Certification of Chief Executive Officer pursuant to Rule 13a-14 of the Securities Exchange Act of 193431.2 
    
    
    
    Certification of Chief Financial Officer pursuant to Rule 13a-14 of the Securities Exchange Act of 193432.1 
    
    
    
    Certification of Chief Executive Officer pursuant to 18 U.S.C. SECTION 135032.2 
    
    
    
    Certification of Chief Financial Officer pursuant to 18 U.S.C. SECTION 1350
   *
    
    Management contract or compensatory plan.
    
    Filed herewith.