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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 |
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For the fiscal year ended December 31, 2004 |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 |
Commission file number: 000-22433
Brigham Exploration Company
(Exact name of Registrant as Specified in its Charter)
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Delaware |
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75-2692967 |
(State or other jurisdiction of
incorporation or organization) |
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(I.R.S. Employer
Identification No.) |
6300 Bridge Point Parkway, Building 2, Suite 500,
Austin, Texas 78730
(Address of principal executive offices) (Zip Code)
(512) 427-3300
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the
Act:
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Name of Each Exchange on Which Registered |
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None
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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 þ 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. o
Indicate by check mark whether the registrant is an accelerated
filer (as defined in Rule 12 b-2 of the
Act). Yes þ No o
As of June 30, 2004, the registrant had
39,675,115 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, 2004 of $9.20 per
share as reported on The Nasdaq Stock
Marketsm,
was $161.1 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 30, 2005, the registrant had 42,489,396 shares
of voting common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the
Registrant’s 2005 Annual Meeting of Stockholders to be held
on June 8, 2005, 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, 2004.
BRIGHAM EXPLORATION COMPANY
TABLE OF CONTENTS
1
BRIGHAM EXPLORATION COMPANY
2004 ANNUAL REPORT ON FORM 10-K
PART I
Overview
We are a Delaware corporation formed in 1997. 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 new field discoveries, are
complemented by a multi-year inventory of development locations.
Since our inception through December 31, 2004, we have
drilled 651 wells, consisting of 470 exploratory and 181
development wells with an aggregate completion rate of 71%. Over
the last three years through December 31, 2004, we drilled
120 wells, consisting of 50 exploratory and 70 development wells
with an aggregate completion rate of 91%.
We have accumulated 3-D seismic data covering approximately
10,464 square miles (6.7 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 651 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. Over the past three years we have
spent $22.1 million on land and seismic and plan to spend
$13.1 million in 2005.
Combining our geologic and geophysical expertise with a
sophisticated land effort, we manage virtually all 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.
In 2004, we increased our level of drilling activity to further
capitalize on our multi-year inventory of exploration and
development prospects by spending a total of $68.2 million
on drilling expenditures. This represented a 94% increase in
drilling expenditures from 2003. These drilling expenditures
were used to drill 17 exploratory wells and 42 development wells
and for other development activities. We also had one
exploration well, the Mills Ranch #2-98, that was in progress at
December 31, 2004.
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We currently plan to continue with our accelerated level of
drilling activity in 2005, and are currently budgeting to spend
a total of $70.3 million to drill 17 exploratory wells and
20 development wells as well as to drill and complete wells that
were in progress at December 31, 2004 and for other
development activities.
The historical financial information in this section pertaining
to depletion expense and accumulated depletion that are part of
our net proved oil and natural gas properties, has been
restated. For a further discussion of the impact of the
restatement on our selected financial information, see
“Item 6. Selected Consolidated Financial Data,”
“Item 8. Financial Statements and Supplementary
Data — Note 2” and “Item 9A.
Controls and Procedures.”
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:
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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. During 2004, we added
approximately 655 square miles of 3-D seismic data to our
corporate database. |
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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. |
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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 13
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 significant field
discoveries and our history of achieving low all-sources finding
costs over the last three, five and seven years, averaging
$3.69, $2.44 and $2.12 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. |
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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 68% of our drilling
expenditures in 2002, 2003 and 2004 were spent on development
activities. We believe our ability to balance our higher risk
exploratory drilling with lower risk development drilling has
reduced our risk profile. For 2005, we intend to allocate
approximately 51% of our total drilling expenditures to
development activities. See “Item 2. Properties”
and “Item 7. Management’s Discussion and Analysis
of Financial Condition and Results of Operations —
Capital Commitments — Capital Expenditures” for
additional discussion about capital expenditures for 2005. |
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Accelerate Drilling of Our Prospect Inventory. To
capitalize on our multi-year inventory of exploration and
development locations, our goal is to continue with our
accelerated level of drilling activity in 2005. In 2004 we spent
$68.2 million in drilling capital expenditures,
representing a 94% |
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increase over amounts spent in 2003. For 2005 we have budgeted
$70.3 million in drilling capital expenditures. As has
historically been the case, our exploratory drilling will test
several higher risk, but higher reserve potential prospects.
During 2005, including the Mills Ranch #2-98 which was in
progress at December 31, 2004, we plan to drill a total of
eight such high risk high potential exploratory wells, versus
the five and three we drilled in 2004 and 2003, respectively.
See “Item 2. Properties” and “Item 7.
Management’s Discussion and Analysis of Financial Condition
and Results of Operations — Capital
Commitments — Capital Expenditures” for
additional discussion about capital expenditures for 2005. |
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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, 2004, we
operated approximately 64% of the pre-tax PV-10% value of our
proved developed reserves. Further, in 2004 we operated 50% of
the wells we drilled, representing 82% of our drilling capital
expenditures. We expect to operate approximately 73% of the
wells planned for 2005, representing approximately 95% of our
budgeted drilling capital expenditures. |
Exploration and Development Staff
Our experienced exploration staff includes five geophysicists,
eight 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 25 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 22 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.
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 natural 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.
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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 Carry Out 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.” 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. 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. See “Item 8.
Financial Statements and Supplementary Data —
Note 10.”
Competition
The oil and natural gas industry is highly competitive in all of
its phases. We encounter competition from other oil and natural
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
that have 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,
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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, results of operations and cash flows. 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.”
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, results of
operations and cash flows.
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, results of
operations and cash flows in the period such may occur. 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 7, 2005, 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 (EPA), 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. See “Item 7.
Management’s Discussion and Analysis of Financial Condition
and Results of Operations — Risk Factors —
We Are Subject To Various Governmental Regulations and
Environmental Risks That May Cause Us To Incur Substantial
Costs.”
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
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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.
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
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dioxide) and particulates with respect to certain of our
operations. We are required to maintain such permits or meet
general permit requirements. The 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.
See “Item 7. Management’s Discussion and Analysis
of Financial Condition and Results of Operations —
Risk Factors — We Are Subject To Various Governmental
Regulations and Environmental Risks That May Cause Us To Incur
Substantial Costs.”
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 50% of the gross
wells and 85% of the net wells that we drilled during 2004, 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 64% of
the pre-tax PV-10% value of our proved developed reserves at
year-end 2004, 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 Our 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.
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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.
The historical financial information in this section pertaining
to depletion expense and accumulated depletion that are a part
of our net proved oil and natural gas properties, has been
restated. For a further discussion of the impact of the
restatement on our selected financial information, see
“Item 6. Selected Consolidated Financial Data,”
“Item 8. Financial Statements and Supplementary Data
— Note 2” and “Item 9A. Controls and
Procedures.”
For the three-year period ended December 31, 2004, we
completed 109 gross wells (42.4 net) in 120 attempts for a
completion rate of 91% at an average all-sources finding cost of
$3.69 per Mcfe. We had one exploration well that began drilling
in 2004 and is currently in progress. For 2005, we have budgeted
approximately $70.3 million to drill 20 development wells
and 17 exploratory wells, to drill and complete wells that were
in progress at December 31, 2004 and for other development
activities. See “Item 7. Management’s Discussion
and Analysis of Financial Condition and Results of
Operations — Capital Commitments — Capital
Expenditures.” The following is a summary of our properties
by major province as of December 31, 2004, unless otherwise
noted.
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Onshore |
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Texas |
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Anadarko |
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West Texas |
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Gulf Coast |
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Capital expenditures for drilling, land and seismic in 2004 (in
millions)
|
|
$ |
48.5 |
|
|
$ |
30.9 |
|
|
$ |
1.8 |
|
|
$ |
81.2 |
|
| |
|
Proved Reserves at December 31, 2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pre-tax PV10% value (in millions)
|
|
$ |
166.4 |
|
|
$ |
111.1 |
|
|
$ |
17.0 |
|
|
$ |
294.5 |
(a) |
|
Oil (MBbls)
|
|
|
1,848 |
|
|
|
605 |
|
|
|
783 |
|
|
|
3,236 |
|
|
Natural gas (MMcf)
|
|
|
56,217 |
|
|
|
45,035 |
|
|
|
623 |
|
|
|
101,875 |
|
|
Natural gas equivalents (MMcfe)
|
|
|
67,304 |
|
|
|
48,665 |
|
|
|
5,321 |
|
|
|
121,290 |
|
|
% Natural gas
|
|
|
84 |
% |
|
|
93 |
% |
|
|
12 |
% |
|
|
84 |
% |
| |
|
Average daily production (MMcfe/d)
|
|
|
20.9 |
|
|
|
9.7 |
|
|
|
3.5 |
|
|
|
34.1 |
|
| |
|
Productive wells at December 31, 2004
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
76 |
|
|
|
168 |
|
|
|
89 |
|
|
|
333 |
|
|
Net
|
|
|
28.0 |
|
|
|
35.7 |
|
|
|
25.1 |
|
|
|
88.8 |
|
| |
|
3-D Seismic Data (square miles)
|
|
|
3,763 |
|
|
|
2,204 |
|
|
|
4,497 |
|
|
|
10,464 |
|
|
|
| (a) |
Standardized measure at December 31, 2004, was
$239.7 million. |
Onshore 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 and accumulated knowledge base in this
province, particularly given our recent drilling successes,
provides us with significant
9
competitive advantages. The majority of our onshore Texas Gulf
Coast activity is currently concentrated in the Vicksburg and
Frio trends.
Over the past three years approximately 64% of our total capital
expenditures for drilling, land and seismic have been allocated
to our onshore Texas Gulf Coast region where we have completed
41 gross wells (21.4 net) in 46 attempts for a completion rate
of 89%. Production from our onshore Texas Gulf Coast province
represented 61% of our average daily production in 2004, up from
53% in 2002.
During 2004, we completed 16 gross wells (10.3 net) in 19
attempts for a completion rate of 84% in this province. Ten of
these wells were exploratory, nine were developmental and we
operated 17 of the 19 wells that we drilled.
During 2004, we spent $48.5 million on drilling, land and
seismic in our onshore Texas Gulf Coast province. For 2005, we
are currently planning to spend approximately $52.8 million
on drilling, land and seismic. Approximately 17% of this will be
allocated to land and seismic expenditures with the remaining
83% allocated to the drilling of wells and other development
activities. Approximately $17 million of our planned
drilling expenditures will be allocated to drill seven
exploration wells with an average working interest of 64% and to
drill and complete wells that were in progress at
December 31, 2004. The remaining $26.8 million of our
2005 drilling expenditures will be allocated to drill ten
development wells with an average working interest of 65% and
other development drilling activities.
Within the Gulf Coast, approximately 24% of our 2004 drilling
capital expenditures were allocated to the Vicksburg trend and
27% were allocated to the Frio trend. In 2004, our development
drilling was focused principally in the Vicksburg trend in
Brooks County, Texas in our Home Run, Floyd Fault Block and
Floyd South Fields. In addition, we significantly increased our
working interest and net reserves in the Triple Crown Field with
the successful completion of our Triple Crown North well, the D.
J. Sullivan C #30. Our decision to drill the D. J. Sullivan
C #30 late in 2004 coincided with the closing of a joint venture
with an industry participant, where we were able to increase our
working interest from 34% to 57.5% in 780 acres on the northeast
side of our Diablo Project. Much of our exploratory activity in
the Vicksburg trend has been driven by other similar joint
ventures with our industry participant, which has substantial
acreage holdings in the area. We expect to drill up to eight
development wells in the Triple Crown North joint venture area
of the Triple Crown Field over the next several years. We also
expect to drill up to four development wells on acreage adjacent
to our Triple Crown Field. Two additional joint ventures with
the same industry participant resulted in two unsuccessful wells
drilled in 2004. The Sullivan E #1 was drilled in early 2004 as
part of a joint venture where we had the opportunity to earn an
interest in 4,353 acres in an untested fault block on the
southeast side of our Diablo Project. The D. J. Sullivan A #1
was drilled in late 2004 as part of a joint venture where we had
the opportunity to earn an interest in approximately 1,000 acres
on an untested Vicksburg structure several miles to the east of
our Diablo Project. We do not anticipate drilling additional
wells as part of either of these two joint ventures at the
present time. However, we continue to have discussions with our
industry participant about other exploratory joint venture
opportunities in the area, and expect to continue to expand our
activities in the trend.
In total, we drilled six Vicksburg trend wells during 2004,
including two exploratory and four development wells. For 2005,
we currently plan to spend $14.7 million to drill five
development wells in our Home Run, Floyd Fault Block and Triple
Crown Fields, to drill and complete wells that were in progress
at December 31, 2004 and for other development activities.
We will retain an average working interest of 55% in these
development wells.
In the Frio trend, we made a new field discovery with the
successful completion of our Appling Deep Field discovery well,
the Sartwelle #3. The Sartwelle #3 was a deep Frio test in our
Bayou Bengal project. Our Bayou Bengal project is a 131 square
mile 3-D seismic project located primarily in Calhoun County,
Texas that we completed in early 2004. We expect to drill up to
six development wells in the Appling Deep Field over the next
several years. Through year-end 2004, we had drilled a total of
six wells in our Bayou Bengal project, with six wells planned
for 2005. Two of these six planned 2005 wells will be deep,
higher risk and higher reserve potential Frio tests similar to
the Sartwelle #3. As was the case in
10
2004, in 2005 we will continue to actively drill wells in our
other existing Frio 3-D seismic projects including General
Patton, Millennium and Jughole. We are currently drilling
another of our higher risk and higher reserve potential Frio
tests in our Millennium project area which is in the same area
in which we discovered our Providence Field in 2001. We retain a
50% working interest in the Wyse #1, which will test the Lower
Frio adjacent to the 75 Bcfe Rugely Field. Furthermore, in 2005
we intend to drill exploration wells in two of our recently
completed 3-D seismic projects. The first project, our 158
square mile Alamo project, and the second project that began in
late 2004 and completed in early 2005, our 120 square mile
General Lee project, are both located in the same geographic
region as our Bayou Bengal project. We have recently closed on a
third new Frio 3-D seismic project, encompassing approximately
33,885 option acres located along the lower Texas Gulf Coast. We
expect to begin interpreting 3-D seismic data from this project
by the second quarter of 2005, and believe that it is likely
that we will have additional drilling projects available in this
area later in 2005.
In total, we drilled 13 Frio trend wells during 2004, including
eight exploratory and five development wells. For 2005, we have
budgeted to spend $26.7 million to drill six exploration
wells with an average working interest of 67%, and five
development wells with an average working interest of 75%, to
drill and complete wells that were in progress at
December 31, 2004 and for other development activities.
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 Hunton, Springer Channel and Springer Bar trends.
However, given the success of several our recent development
wells in our Hobart Granite Wash trend in Hemphill County,
Texas, developmental activity in this field could accelerate
during the second half of 2005.
Over the past three years approximately 33% of our total capital
expenditures for drilling, land and seismic have been allocated
to our Anadarko Basin region where we have completed 56 gross
wells (17.4 net) in 60 attempts for a completion rate of 93%. We
also have one exploration well, the Mills Ranch #2-98 that began
drilling in 2004 and is currently in progress. Production from
the Anadarko Basin represented 29% of our average daily
production in 2004, up from 26% in 2002.
During 2004, we completed 37 gross wells (10.8 net) in 38
attempts for a completion rate of 97%. Five of these wells were
exploration wells and 33 were developmental. We operated 10 of
the 38 wells that we drilled in the Anadarko Basin in 2004 and
are the operator of the Mills Ranch #2-98.
In total, we spent $30.9 million on drilling, land and
seismic during 2004 in our Anadarko Basin province. For 2005, we
are currently planning to spend approximately $27 million
on drilling, land and seismic. Approximately $3.5 million of
this will be allocated to land and seismic expenditures, with
the remaining $23.5 million allocated to the drilling of
wells and other development activities. Approximately $14.8
million of our planned drilling expenditures will be allocated
to drill seven exploration wells with an average working
interest of 46% and to drill and complete wells that were in
progress at December 31, 2004. The remaining
$8.7 million of our planned drilling expenditures will be
allocated to drill ten development wells with an average working
interest of 37% and to other development drilling activities.
Furthermore, approximately $12.1 million of our 2005
drilling expenditures budgeted for our Anadarko
11
Basin province are allocated to the Hunton trend,
$5.9 million is allocated to the Springer trends and
$4.5 million is allocated to the Granite Wash trend.
Within the Anadarko Basin, approximately 45% of our 2004 capital
expenditures were allocated to the Hunton trend, 11% to the
Springer trends and 9% to the Granite Wash trend. Within our
Hunton trend, our first development well drilled on the eastern
end of the roughly five mile long Mills Ranch Field was the
Mills Ranch #1-99S. In order to minimize drilling cost, the well
was a reentry of a previously abandoned Arbuckle well. The well
was spud in January 2004 and was targeting to drill through both
the Hunton and Arbuckle formations, reaching an estimated total
depth of 24,000’ in the second quarter. Unfortunately in
May, after drilling into our primary Hunton pay interval, the
drill pipe became stuck and the well had to be sidetracked,
requiring us to re-drill approximately 3,000 feet. The
sidetracking operation delayed the completion of the well until
September and precluded us from reaching our secondary Arbuckle
objective. The well was put on production in late September and
initially produced at a gross rate of 8.7 MMcfe per day.
However, production from the well has declined dramatically and
at year-end 2004 the well was only producing 1.0 MMcfe per day.
We are currently evaluating what options we have to enhance the
performance of the well. A second Mills Ranch Field well, the
Mills Ranch #2-98, was spud in November 2004 on the western side
of the field where we have completed two prior Hunton wells.
This well targets the Arbuckle and shallower potential pay
intervals and is expected to reach total depth in the second
quarter of 2005. At present, one additional Hunton/ Arbuckle
well is scheduled for 2005. This well is a high risk and high
reserve potential exploration test of another structure in the
area. This well is expected to spud by mid-year and is estimated
to reach total depth in the fourth quarter of 2005.
In the Texas panhandle of the Anadarko Basin, we have drilled
six recent wells to evaluate the economics of a potentially
extensive drilling program in the Granite Wash formation. We
have approximately 3,800 contiguous gross acres in the area.
Adjacent acreage has and continues to experience extensive
drilling by other operators. Most of this acreage has been
developed on 40 acre spacing, although some acreage is being
developed on 20 acre spacing. We are currently evaluating the
results of the five most recently drilled Granite Wash wells,
with the last two wells having experienced higher initial
producing rates. We currently have three wells budgeted for the
area in the second half of 2005. However, should results merit,
we may accelerate development of the acreage during the second
half of 2005. Development on 40 acre spacing would require up to
90 potential wells, while development on 20 acre spacing could
require as many as 180 potential wells.
West Texas
West Texas is predominantly an oil producing province with
generally longer life 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 approximately 3% of our total capital
expenditures for drilling, land and seismic have been allocated
to our West Texas province where we have completed 12 gross
wells (3.6 net) in 14 attempts for a completion rate of 86%.
Production from West Texas represented 10% of our average daily
production in 2004 down from 21% in 2002.
During 2004 we completed one gross well (0.9 net) in two
attempts for a completion rate of 50%. Both of these wells were
exploration wells and were operated by us.
In total, we spent $1.8 million on drilling, land and
seismic during 2004 in our West Texas province. For 2005, we are
currently planning to spend approximately $3.6 million on
drilling, land and seismic. Approximately $600,000 of this will
be allocated to land and seismic expenditures, $2.9 million
will be allocated to drill three exploration wells with an
average working interest of 82% and the remainder will be
allocated to other development activities.
12
Given our large inventory of 3-D seismic data in West Texas, our
strong historical results in the province, and the currently
strong oil prices, we have begun to focus more of our resources
on exploiting our West Texas asset base. We expect this more
intense focus to positively impact our drilling program by late
2005 and 2006.
3-D Seismic Exploration
We have accumulated 3-D seismic data covering approximately
10,464 square miles (6.7 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
651 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. Since 1998 we have continued to add to our 3-D
seismic database within our core trends on a more conservative
pace. 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.
Over the last fourteen 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.
Historically, 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 virtually all 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.
13
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 75
square miles of non-proprietary and 56 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.
During 2004, we added approximately 655 square miles of 3-D
seismic data to our corporate database. During 2004, we acquired
approximately 57 square miles of non-proprietary and 101 square
miles of new proprietary 3-D seismic data in our Alamo project
located in the Frio trend of the Upper Texas Gulf Coast. We sold
a working interest in Alamo to an industry participant on a
promoted basis and retained a 75% working interest in the
project. In late 2004 and early 2005, we acquired approximately
120 square miles of new proprietary 3-D seismic data in our
General Lee project, also located in the Frio trend of the Upper
Texas Gulf Coast. We sold a working interest in General Lee to
an industry participant on a promoted basis and retained a 75%
working interest.
See “ — Onshore Texas Gulf Coast,”
“ — Anadarko Basin,” “ — West
Texas,” and “Item 7. Management’s Discussion
and Analysis of Financial Condition and Results of
Operations — Capital Commitments — Capital
Expenditures” for additional discussion regarding 2005
seismic capital expenditures.
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 — Senior
Credit Facility” and “Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of
Operations — Capital Commitments — Senior
Subordinated Notes.”
14
Oil and Natural Gas Reserves
Our estimated total net proved reserves of oil and natural gas
as of December 31, 2004, 2003 and 2002, pre-tax PV-10%
value, standardized measure and the estimated future development
cost attributable to these reserves as of those dates were as
follows.
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
At December 31, |
| |
|
|
| |
|
2004 |
|
2003 |
|
2002 |
| |
|
|
|
|
|
|
|
Estimated Net Proved Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
3,236 |
|
|
|
4,130 |
|
|
|
3,607 |
|
|
Natural gas (MMcf)
|
|
|
101,875 |
|
|
|
109,403 |
|
|
|
99,428 |
|
| |
Natural gas equivalent (MMcfe)
|
|
|
121,290 |
|
|
|
134,182 |
|
|
|
121,070 |
|
|
Proved developed reserves as a percentage of net proved reserves
|
|
|
50 |
% |
|
|
50 |
% |
|
|
46 |
% |
|
Pre-tax PV-10% (in millions)
|
|
$ |
294.5 |
|
|
$ |
343.8 |
|
|
$ |
307.4 |
|
|
Standardized measure (in millions)
|
|
|
239.7 |
|
|
|
261.6 |
|
|
|
239.7 |
|
|
Estimated future development cost (in millions)
|
|
|
79.9 |
|
|
|
59.0 |
|
|
|
48.7 |
|
|
Base price used to calculate reserves(a):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per MMbtu)
|
|
$ |
6.19 |
|
|
$ |
5.83 |
|
|
$ |
4.74 |
|
|
Oil (per Bbl)
|
|
|
43.46 |
|
|
|
32.55 |
|
|
|
31.25 |
|
|
|
|
|
(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. We do not report
reserve information to any other government agency.
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.
15
Drilling Activities
We drilled, or participated in the drilling of, the following
number of wells during the periods indicated.
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, |
| |
|
|
| |
|
2004(a) |
|
2003 |
|
2002(b) |
| |
|
|
|
|
|
|
| |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
|
9 |
|
|
|
4.4 |
|
|
|
14 |
|
|
|
6.8 |
|
|
|
4 |
|
|
|
0.9 |
|
|
Oil
|
|
|
1 |
|
|
|
0.9 |
|
|
|
4 |
|
|
|
1.3 |
|
|
|
6 |
|
|
|
0.9 |
|
|
Non-productive
|
|
|
7 |
|
|
|
5.2 |
|
|
|
4 |
|
|
|
1.8 |
|
|
|
1 |
|
|
|
0.7 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Total
|
|
|
17 |
|
|
|
10.5 |
|
|
|
22 |
|
|
|
9.9 |
|
|
|
11 |
|
|
|
2.5 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
|
|
|
35 |
|
|
|
13.9 |
|
|
|
11 |
|
|
|
3.9 |
|
|
|
7 |
|
|
|
2.4 |
|
|
Oil
|
|
|
2 |
|
|
|
0.3 |
|
|
|
1 |
|
|
|
0.4 |
|
|
|
4 |
|
|
|
1.7 |
|
|
Non-productive
|
|
|
5 |
|
|
|
1.5 |
|
|
|
3 |
|
|
|
1.8 |
|
|
|
1 |
|
|
|
0.3 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Total
|
|
|
42 |
|
|
|
15.7 |
|
|
|
15 |
|
|
|
6.1 |
|
|
|
12 |
|
|
|
4.4 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Excludes one (1.0 net) exploratory well that is currently
drilling. |
|
(b) |
|
Excludes one (0.2 net) development well that is productive
but is temporarily abandoned. There are no current plans to put
this well on production. |
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.
16
Productive Wells and Acreage
Productive Wells
The following table sets forth our ownership interest at
December 31, 2004 in productive oil and natural gas wells
in the areas indicated. Wells are classified as oil or natural
gas wells according to their predominant production stream.
Gross wells are the total number of producing wells in which we
have an interest, and net wells are determined by multiplying
gross wells by our average working interest.
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Natural Gas |
|
Oil |
|
Total |
| |
|
|
|
|
|
|
| |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Onshore Texas Gulf Coast
|
|
|
56 |
|
|
|
23.2 |
|
|
|
20 |
|
|
|
4.8 |
|
|
|
76 |
|
|
|
28.0 |
|
|
Anadarko Basin
|
|
|
149 |
|
|
|
31.9 |
|
|
|
19 |
|
|
|
3.8 |
|
|
|
168 |
|
|
|
35.7 |
|
|
West Texas and other
|
|
|
13 |
|
|
|
1.6 |
|
|
|
76 |
|
|
|
23.5 |
|
|
|
89 |
|
|
|
25.1 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Total
|
|
|
218 |
|
|
|
56.7 |
|
|
|
115 |
|
|
|
32.1 |
|
|
|
333 |
|
|
|
88.8 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
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
interest in at December 31, 2004.
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Developed |
|
Undeveloped |
|
Total |
| |
|
|
|
|
|
|
| |
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Onshore Texas Gulf Coast
|
|
|
15,255 |
|
|
|
7,591 |
|
|
|
19,512 |
|
|
|
12,532 |
|
|
|
34,767 |
|
|
|
20,123 |
|
|
Anadarko Basin
|
|
|
50,091 |
|
|
|
27,270 |
|
|
|
26,133 |
|
|
|
14,397 |
|
|
|
76,224 |
|
|
|
41,667 |
|
|
West Texas
|
|
|
17,762 |
|
|
|
6,255 |
|
|
|
2,160 |
|
|
|
1,627 |
|
|
|
19,922 |
|
|
|
7,882 |
|
|
Other
|
|
|
2,732 |
|
|
|
967 |
|
|
|
— |
|
|
|
— |
|
|
|
2,732 |
|
|
|
967 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Total
|
|
|
85,840 |
|
|
|
42,083 |
|
|
|
47,805 |
|
|
|
28,556 |
|
|
|
133,645 |
|
|
|
70,639 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In addition, as of December 31, 2004, we also owned
2,509 gross and 1,826 net mineral acres.
All the leases for the undeveloped acreage summarized in the
preceding table will expire at the end of their respective
primary terms unless the existing leases are renewed, production
has been obtained from the acreage subject to the lease prior to
that date, or some other “savings clause” is
implicated. The following table sets forth the minimum remaining
terms of leases for the gross and net undeveloped acreage.
| |
|
|
|
|
|
|
|
|
|
| |
|
Acres Expiring |
| |
|
|
| Twelve Months Ending: |
|
Gross |
|
Net |
| |
|
|
|
|
|
December 31, 2005
|
|
|
14,271 |
|
|
|
7,449 |
|
|
December 31, 2006
|
|
|
17,357 |
|
|
|
10,059 |
|
|
December 31, 2007
|
|
|
9,506 |
|
|
|
6,690 |
|
|
Thereafter
|
|
|
6,671 |
|
|
|
4,358 |
|
| |
|
|
|
|
|
|
|
|
| |
Total
|
|
|
47,805 |
|
|
|
28,556 |
|
| |
|
|
|
|
|
|
|
|
17
In addition, as of December 31, 2004, we had lease options
and rights of first refusal to acquire additional acres. The
following table sets forth the expiration year of our options
and right of first refusal agreements and the gross and net
acres associated with those options and right of first refusal
agreements.
| |
|
|
|
|
|
|
|
|
| |
|
Acres Expiring |
| |
|
|
| Twelve Months Ending: |
|
Gross |
|
Net |
| |
|
|
|
|
|
December 31, 2005
|
|
|
62,638 |
|
|
|
55,767 |
|
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, |
| |
|
|
| |
|
2004 |
|
2003 |
|
2002 |
| |
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Oil (MBbls)
|
|
|
573 |
|
|
|
720 |
|
|
|
701 |
|
| |
Natural gas (MMcf)
|
|
|
8,830 |
|
|
|
6,356 |
|
|
|
5,791 |
|
| |
Natural gas equivalent (MMcfe)
|
|
|
12,265 |
|
|
|
10,674 |
|
|
|
9,996 |
|
|
Average sales price per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
| |
Oil revenues (per Bbl)
|
|
$ |
40.13 |
|
|
$ |
30.79 |
|
|
$ |
25.17 |
|
| |
Effects of hedging activities (per Bbl)
|
|
|
(4.96 |
) |
|
|
(2.62 |
) |
|
|
(1.62 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Average price (per Bbl)
|
|
$ |
35.17 |
|
|
$ |
28.17 |
|
|
$ |
23.55 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Natural gas revenues (per Mcf)
|
|
$ |
6.05 |
|
|
$ |
5.68 |
|
|
$ |
3.33 |
|
| |
Effects of hedging activities (per Mcf)
|
|
|
(0.21 |
) |
|
|
(0.76 |
) |
|
|
(0.12 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Average price (per Mcf)
|
|
$ |
5.84 |
|
|
$ |
4.92 |
|
|
$ |
3.21 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
| |
Total oil and natural gas revenues (per Mcfe)
|
|
$ |
6.23 |
|
|
$ |
5.46 |
|
|
$ |
3.70 |
|
| |
Effects of hedging activities (per Mcfe)
|
|
|
(0.38 |
) |
|
|
(0.63 |
) |
|
|
(0.19 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Average price (per Mcfe)
|
|
$ |
5.85 |
|
|
$ |
4.83 |
|
|
$ |
3.51 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Average production costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Lease operating expenses (per Mcfe)
|
|
$ |
0.43 |
|
|
$ |
0.43 |
|
|
$ |
0.32 |
|
| |
Ad valorem taxes (per Mcfe)
|
|
|
0.07 |
|
|
|
0.06 |
|
|
|
0.06 |
|
| |
Production taxes (per Mcfe)
|
|
|
0.25 |
|
|
|
0.23 |
|
|
|
0.20 |
|
18
|
|
| 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 received
approximately $440,000 as a result of this settlement. The
amount of the settlement reduced capitalized well cost. In
addition, Massey relinquished its $445,819 counterclaim.
On October 8, 2002, relatives of a contractor’s
employee filed a wrongful death action against us and three
other contractors in the District Court of Matagorda County,
Texas in connection with the employee’s death at our
Burkhart #1-R location. On March 23, 2004, a jury
determined that we had no liability in the accidental death of
the contractor’s employee. The trial judge, however,
granted plaintiffs’ motion for a new trial. We expect the
new trial to take place in June 2005. We believe we have
adequate insurance to cover any potential damage award (subject
to a $5,000 deductible). At this point in time, we cannot
predict the outcome of this case.
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 for services rendered. In April
2004, the case was settled, resulting in a payment by the
contractor to our co-participants and us of $325,000. In
addition, the contractor relinquished its counterclaim against
us. Based on the amount of the settlement, the additional costs
that were covered by insurance, and the insurer being subrogated
to our claim, we did 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
reviewed the reports of the Referee and the original
Administrative Law Judge and affirmed those rulings. The
operator then filed an appeal with the Oklahoma Supreme Court.
In January 2005, the parties settled the dispute. The operator
agreed to recognize our full interest in the Stonehocker well,
and also agreed to reverse certain charges made under the
operating agreements of six additional wells in which we own an
interest.
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 asserted that it did not relinquish
its entire interest, but rather became subject only to a
400 percent payout provision. In November 2003, this
company filed a lawsuit in the District Court of Brazoria
County, Texas, against us for breach of contract. If the suit
was successful, it could have resulted in a judgment of as much
as $700,000. In April 2004, we settled the case, agreeing to pay
the company $350,000 in return for the company’s assignment
of all its right, title and interest in the unit for the well.
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. Defendants denied any wrongdoing
and asserted a counterclaim against us for alleged tortuous
interference with an existing business relationship between the
company and its employee. In April 2004, we settled the case.
The company agreed not to compete
19
against us in a specified area for two years, assigned us a
small overriding royalty in three tracts, paid us $50,000, and
released its counterclaim.
As of December 31, 2004, 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 Security Holders |
No matter was submitted to a vote of our security holders during
the fourth quarter of 2004.
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 31,
2005.
| |
|
|
|
|
|
|
| Name |
|
Age |
|
Position |
| |
|
|
|
|
|
Ben M. Brigham
|
|
|
45 |
|
|
Chief Executive Officer, President and Chairman |
|
Eugene B. Shepherd, Jr
|
|
|
46 |
|
|
Executive Vice President and Chief Financial Officer |
|
David T. Brigham
|
|
|
44 |
|
|
Executive Vice President — Land and Administration and
Director |
|
A. Lance Langford
|
|
|
42 |
|
|
Executive Vice President — Operations |
|
Jeffery E. Larson
|
|
|
46 |
|
|
Executive Vice President — Exploration |
Ben M. “Bud” Brigham has 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 at Austin. 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. Brigham joined 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
20
Land Management from the University of Texas and a J.D. from
Texas Tech School of Law. Mr. Brigham is the brother of Ben
M. Brigham, Chief Executive Officer, President and Chairman of
the Board.
A. Lance Langford joined 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. Larson joined 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.
PART II
|
|
| Item 5. |
Market for Registrant’s Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity
Securities |
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 | |
|
Low | |
| |
|
| |
|
| |
|
2003:
|
|
|
|
|
|
|
|
|
| |
First Quarter
|
|
$ |
6.000 |
|
|
|
4.400 |
|
| |
Second Quarter
|
|
|
5.740 |
|
|
|
4.500 |
|
| |
Third Quarter
|
|
|
7.200 |
|
|
|
4.750 |
|
| |
Fourth Quarter
|
|
|
8.410 |
|
|
|
6.260 |
|
|
2004:
|
|
|
|
|
|
|
|
|
| |
First Quarter
|
|
$ |
8.630 |
|
|
$ |
6.600 |
|
| |
Second Quarter
|
|
|
10.040 |
|
|
|
7.341 |
|
| |
Third Quarter
|
|
|
9.890 |
|
|
|
7.560 |
|
| |
Fourth Quarter
|
|
|
10.050 |
|
|
|
7.720 |
|
The closing market price of our common stock on March 30,
2005 was $8.89 per share. As of March 30, 2005, there
were an estimated 118 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.
21
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
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.”
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, 2004.
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Number of | |
|
|
|
Number of Securities | |
| |
|
Securities to be | |
|
|
|
Remaining Available | |
| |
|
Issued upon | |
|
Weighted-Average | |
|
for Future Issuance | |
| |
|
Exercise of | |
|
Price of | |
|
Under Equity | |
| Plan Category |
|
Outstanding Options | |
|
Outstanding Options | |
|
Compensation Plans | |
| |
|
| |
|
| |
|
| |
|
Equity compensation plans approved by security holders(a)
|
|
|
2,676,100 |
|
|
$ |
6.01 |
|
|
|
1,730,850 |
|
|
Equity compensation plans not approved by security holders
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
| |
Total
|
|
|
2,676,100 |
|
|
$ |
6.01 |
|
|
|
1,730,850 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Does not include 325,000 shares of restricted stock at
December 31, 2004. |
Issuer Purchases of Equity Securities
In 2004, 2003 and 2002 we elected to allow employees to deliver
shares of vested restricted stock with a fair market value equal
to their federal, state and local tax withholding amounts on the
date of issue in lieu of cash payment.
| |
|
|
|
|
|
|
|
|
| |
|
Total Number of | |
|
Average Price | |
| Period |
|
Shares Purchased | |
|
Paid per Share | |
| |
|
| |
|
| |
|
October 2004
|
|
|
15,790 |
|
|
$ |
9.205 |
|
|
January 2004
|
|
|
19,596 |
|
|
|
7.970 |
|
|
October 2003
|
|
|
16,351 |
|
|
|
6.705 |
|
|
October 2002
|
|
|
18,665 |
|
|
|
4.030 |
|
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. We received no proceeds
from the sale of the common stock.
In December 2002, we issued 243,902 unregistered shares of our
common stock. The common stock was issued connection with the
cash exercise of warrants to purchase 243,902 shares
of our common stock for $2.5625 per share. We received cash
proceeds of $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 to a group of institutional investors.
This group of investors was led by affiliates of two members of
our then current Board of Directors. At the time the warrants
were exercised,
22
one of these two board members was no longer a member of our
board. The remaining warrants were exercised in February 2003.
In February 2003, we issued 248,028 unregistered shares of our
common stock. The common stock was issued in connection with a
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 to a
group of institutional investors. This group of investors was
led by affiliates of two members of our then current Board of
Directors. At the time the warrants were exercised, one of these
two board members was no longer a member of our board.
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. 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. We received no proceeds from the
sale of the common stock.
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.
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
23
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 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 had 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. In
June 2004, we filed a Certificate of Elimination to eliminate
our Series B preferred stock.
24
|
|
| 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. The information
for the years from 2000 until 2003 has been restated. For a
further discussion of this restatement and the restatement
amounts, see “Item 8. Financial Statements and
Supplementary Data — Note 2.” See the notes
to the table below for the impact of this restatement on 2001
and 2000.
We derived the statement of operations data and statement of
cash flows data for the years ended December 31, 2004, 2003
and 2002, and balance sheet data as of December 31, 2004
and 2003 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, 2001 and 2000 and the balance sheet data as of
December 31, 2002, 2001 and 2000, from our accounting books
and records.
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, |
| |
|
|
| |
|
2004 |
|
2003 |
|
2002 |
|
2001 |
|
2000 |
| |
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
Restated(1) |
|
Restated(1) |
|
Restated(1)(2) |
|
Restated(1)(2) |
| |
|
(In thousands, except per share information) |
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales
|
|
$ |
71,713 |
|
|
$ |
51,545 |
|
|
$ |
35,100 |
|
|
$ |
32,293 |
|
|
$ |
19,143 |
|
|
Other revenues
|
|
|
515 |
|
|
|
132 |
|
|
|
76 |
|
|
|
255 |
|
|
|
69 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Total revenues
|
|
|
72,228 |
|
|
|
51,677 |
|
|
|
35,176 |
|
|
|
32,548 |
|
|
|
19,212 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
|
6,173 |
|
|
|
5,200 |
|
|
|
3,759 |
|
|
|
3,486 |
|
|
|
2,139 |
|
|
Production taxes
|
|
|
3,107 |
|
|
|
2,477 |
|
|
|
1,977 |
|
|
|
1,511 |
|
|
|
1,786 |
|
|
General and administrative expenses
|
|
|
5,392 |
|
|
|
4,500 |
|
|
|
4,971 |
|
|
|
3,638 |
|
|
|
3,100 |
|
|
Depletion of oil and natural gas properties
|
|
|
23,844 |
|
|
|
16,819 |
|
|
|
14,694 |
|
|
|
13,225 |
|
|
|
7,601 |
|
|
Depreciation and amortization
|
|
|
722 |
|
|
|
629 |
|
|
|
440 |
|
|
|
677 |
|
|
|
620 |
|
|
Accretion of discount on asset retirement obligations
|
|
|
159 |
|
|
|
142 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Total costs and expenses
|
|
|
39,397 |
|
|
|
29,767 |
|
|
|
25,841 |
|
|
|
22,537 |
|
|
|
15,246 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
Operating income (loss)
|
|
|
32,831 |
|
|
|
21,910 |
|
|
|
9,335 |
|
|
|
10,011 |
|
|
|
3,966 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Interest expense, net
|
|
|
(3,144 |
) |
|
|
(4,815 |
) |
|
|
(6,238 |
) |
|
|
(6,681 |
) |
|
|
(9,906 |
) |
| |
Interest income
|
|
|
84 |
|
|
|
45 |
|
|
|
119 |
|
|
|
264 |
|
|
|
108 |
|
| |
Other income (expense)
|
|
|
742 |
|
|
|
(601 |
) |
|
|
(310 |
) |
|
|
8,080 |
|
|
|
(9,504 |
) |
| |
Debt conversion expense
|
|
|
— |
|
|
|
— |
|
|
|
(630 |
) |
|
|
— |
|
|
|
— |
|
| |
Gain on refinancing of debt
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
32,267 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Total other income (expense)
|
|
|
(2,318 |
) |
|
|
(5,371 |
) |
|
|
(7,059 |
) |
|
|
1,663 |
|
|
|
12,965 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes and cumulative effect of
change in accounting principle
|
|
$ |
30,513 |
|
|
$ |
16,539 |
|
|
$ |
2,276 |
|
|
$ |
11,674 |
|
|
$ |
16,931 |
|
|
Income tax benefit (expense)
|
|
|
(10,863 |
) |
|
|
1,223 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Income (loss) before cumulative effect of change in accounting
principle
|
|
|
19,650 |
|
|
|
17,762 |
|
|
|
2,276 |
|
|
|
11,674 |
|
|
|
16,931 |
|
|
Cumulative effect of change in accounting principle
|
|
|
— |
|
|
|
268 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Net income (loss)
|
|
|
19,650 |
|
|
|
18,030 |
|
|
|
2,276 |
|
|
|
11,674 |
|
|
|
16,931 |
|
|
Preferred dividend and accretion
|
|
|
— |
|
|
|
3,448 |
|
|
|
2,952 |
|
|
|
2,450 |
|
|
|
275 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Net income (loss) available to common stockholders
|
|
$ |
19,650 |
|
|
$ |
14,582 |
|
|
$ |
(676 |
) |
|
$ |
9,224 |
|
|
$ |
16,656 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share before cumulative effect of change
in accounting principle
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Basic
|
|
$ |
0.49 |
|
|
$ |
0.62 |
|
|
$ |
(0.04 |
) |
|
$ |
0.58 |
|
|
$ |
1.03 |
|
| |
Diluted
|
|
|
0.47 |
|
|
|
0.51 |
|
|
|
(0.04 |
) |
|
|
0.44 |
|
|
|
1.03 |
|
|
Weighted average shares outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Basic
|
|
|
40,445 |
|
|
|
23,363 |
|
|
|
16,138 |
|
|
|
15,988 |
|
|
|
16,241 |
|
| |
Diluted
|
|
|
41,616 |
|
|
|
34,354 |
|
|
|
16,138 |
|
|
|
28,205 |
|
|
|
16,241 |
|
25
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
At December 31, |
| |
|
|
| |
|
2004 |
|
2003 |
|
2002 |
|
2001(2) |
|
2000(2) |
| |
|
|
|
|
|
|
|
|
|
|
| |
|
(In thousands) |
|
Statement of Cash Flows Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Operating activities
|
|
$ |
56,381 |
|
|
$ |
41,691 |
|
|
$ |
28,973 |
|
|
$ |
18,922 |
|
|
$ |
(4,635 |
) |
| |
Investing activities
|
|
|
(84,645 |
) |
|
|
(46,089 |
) |
|
|
(27,206 |
) |
|
|
(33,571 |
) |
|
|
(26,071 |
) |
| |
Financing activities
|
|
|
24,766 |
|
|
|
(5,141 |
) |
|
|
8,439 |
|
|
|
18,924 |
|
|
|
28,801 |
|
|
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$ |
2,281 |
|
|
$ |
5,779 |
|
|
$ |
15,318 |
|
|
$ |
5,112 |
|
|
$ |
837 |
|
|
Oil and natural gas properties, net (restated)(1)(2)
|
|
|
261,979 |
|
|
|
198,490 |
|
|
|
166,006 |
|
|
|
153,017 |
|
|
|
130,630 |
|
|
Total assets (restated)(1)(2)
|
|
|
286,307 |
|
|
|
224,982 |
|
|
|
203,085 |
|
|
|
174,201 |
|
|
|
148,051 |
|
|
Long-term debt
|
|
|
41,000 |
|
|
|
39,000 |
|
|
|
81,797 |
|
|
|
91,721 |
|
|
|
82,000 |
|
|
Series A preferred stock, mandatorily redeemable
|
|
|
9,520 |
|
|
|
8,794 |
|
|
|
19,540 |
|
|
|
16,614 |
|
|
|
8,558 |
|
|
Series B preferred stock, mandatorily redeemable
|
|
|
— |
|
|
|
— |
|
|
|
4,777 |
|
|
|
— |
|
|
|
— |
|
|
Total stockholders’ equity (restated)(1)(2)
|
|
|
183,276 |
|
|
|
139,111 |
|
|
|
62,775 |
|
|
|
50,727 |
|
|
|
35,897 |
|
|
|
| (1) |
The historical financial information pertaining to depletion
expense and accumulated depletion that are a part of our net
proved oil and natural gas properties has been restated. The
total cumulative impact of the restatement was an increase of
our previously reported stockholders’ equity as of
September 30, 2004 (the most recent balance sheet filed) of
approximately $676,000. The cumulative impact includes an
increase to beginning stockholders’ equity as of
January 1, 2002 of approximately $1,126,000. For a further
discussion of the impact of the restatement on our selected
financial information, see “Item 8. Financial
Statements and Supplementary Data — Note 2 and
“Item 9A. Controls and Procedures.” |
| |
| (2) |
The impacts of the historical restatement for the year ended
December 31, 2001 were a decrease in earnings before and
after income taxes of approximately $14,000 and increases to
depletion expense and accumulated depletion of $14,000. Basic
and diluted earnings per share were unchanged for the year ended
December 31, 2001. The impacts of the historical
restatement for the year ended December 31, 2000 were an
increase in earnings before and after income taxes of
approximately $320,000, basic earnings per share of $0.02,
diluted earnings per share of $0.02, and decreases to depletion
expense and accumulated depletion of $320,000. |
26
|
|
| 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. We utilize the full cost method of
accounting for our proved oil and natural gas properties
included in our consolidated financial statements. During March
2005, in connection with the preparation of our consolidated
financial statements for the year ended December 31, 2004,
we evaluated the manner in which we historically accounted for
depletion expense associated with our oil and natural gas
properties. Historically, we have calculated a depletion rate at
the end of each period within the year based on our updated
reserve estimate. This depletion rate has then been
retroactively applied to year-to-date production with the
adjustment to previously recorded depletion expense recorded in
the current quarter. We determined that the revised depletion
rate should have been applied on a prospective basis to
production in the most current quarterly period only. Therefore,
we determined we had not properly accounted for depletion
expense and related accumulated depletion that are a part of our
net proved oil and natural gas properties. As a result of this
conclusion, we have restated previously issued financial
statements for the years ended December 31, 2003 and 2002,
and reduced our accumulated deficit by $1,126,000 as of
January 1, 2002 to reflect the impact of the revised method
of depletion expense for prior years. The total cumulative
impact of the restatement was an increase of our previously
reported stockholders’ equity as of September 30, 2004
(the most recent balance sheet filed) of approximately $676,000.
These restated amounts have been reflected only in this Annual
Report on Form 10-K, and we did not revise our historically
filed annual and quarterly reports for the impacts of the
restatement. Consequently, you should not rely on historical
information contained in our prior filings since this filing
replaces and revises our historically reported amounts as
further discussed in “Item 8. Financial Statements and
Supplementary Data — Note 2.”
Overview of Our Business
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.
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.
Evaluations of oil and gas reserves are important to the
management of these assets and are also used in the
determination of unit-of-production depletion rates and
impairment evaluations. Oil and gas reserves are divided between
proved and unproved reserves. Proved reserves are the estimated
quantities of natural gas, natural gas liquids and oil that
geological and engineering data demonstrate with reasonable
certainty
27
to be recoverable in futures years from known reservoirs under
existing economic and operating conditions. Unproved reserves
are those with less than reasonable certainty of recoverability.
Proven reserves are classified as (1) proven developed;
(2) proven developed not producing; or (3) proven
undeveloped. Proven developed not producing and undeveloped
reserves will be reclassified to the proven developed category
as new wells are drilled, existing wells are recompleted, and/or
facilities are put in place for the gathering and transportation
of production.
Although we are reasonably certain that proved reserves will be
produced, the timing and ultimate recovery can be affected by a
number of factors including reservoir performance, regulatory
approvals and significant changes in projections of natural gas
and oil prices.
Revisions in previously estimated quantities of proved reserves
can include upward or downward changes due to the evaluation of
new or already existing geologic, reservoir or production data
from wells. Revisions can also result from changes in
performance of enhanced recovery projects, facility capacity, or
natural gas and oil prices.
The method of accounting for natural gas and oil properties
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 natural gas and oil 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, 2004, our depletion expense per unit of
production was $1.94 per Mcfe. A change of
1,000,000 Mcfe in our estimated net proved reserves at
December 31, 2004, would result in a $0.02 per Mcfe
change in our per unit depletion expense and a $368,000 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 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
28
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.”
We use the “full cost” instead of the “successful
efforts” method because it regards all costs incurred in
the acquisition, exploration and development activities as
integral to the results of those activities as a whole, and
therefore associated with our proved reserves. Under the
“successful efforts” method, significant costs such as
the acquisition of 3-D seismic data would be expensed as
incurred rather than amortized over the life of any natural gas
and oil reserves discovered through these activities.
|
|
|
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.
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 will use these NOLs to offset current tax liabilities in
future years. Our NOLs are more fully described in
“Item 8. Financial Statements and Supplementary
Data — Note 9.”
We derive revenue primarily from the sale of produced natural
gas and oil, 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
our entitled ownership percentage of sales of natural gas
delivered to
29
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 “Item 8. Financial
Statements and Supplementary Data — Note 5”
and “Item 8. Financial Statements and Supplementary
Data — Note 12.”
In accordance with Financial Accounting Standards Board
(FASB) requirements SFAS 133, as amended, 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 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 cash flow hedges are included in earnings.
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 September 2004, the Securities and Exchange Commission
(SEC) issued Staff Accounting Bulletin 106
(SAB 106) which provides guidance regarding the interaction
of SFAS 143 with the calculation of depletion and the full
cost ceiling test of oil and gas properties under the full cost
accounting rules of the SEC. The guidance provided in
SAB 106 is not expected to have a material effect on our
consolidated financial position, results of operations or cash
flows.
In December 2004, the Financial Accounting Standards Board
(FASB) issued SFAS No. 123R, ”Share-Based
Payment” (SFAS 123R), which is a revision of
SFAS 123 and supersedes APB Opinion No. 25.
SFAS 123R requires all share-based payments to employees,
including grants of employee stock
30
options, to be valued at fair value on the date of grant, and to
be expensed over the applicable vesting period. Pro forma
disclosure of the income statement effects of share-based
payments is no longer an alternative. SFAS 123R is
effective for all stock-based awards granted on or after
July 1, 2005. In addition, companies must also recognize
compensation expense related to any awards that are not fully
vested as of the effective date. Compensation expense for the
unvested awards will be measured based on the fair value of the
awards previously calculated in developing the pro forma
disclosures in accordance with the provisions of SFAS 123.
We are currently assessing the impact of adopting SFAS 123R
to our consolidated financial statements.
In October 2004, the American Jobs Creation Act of 2004 (AJCA)
was signed into law. In December 2004, the FASB issued Staff
Position No. 109-1 (FSP 109-1), “Application of
FASB Statement No. 109, Accounting for Income Taxes, to the
Tax Deduction on Qualified Production Activities Provided by the
American Jobs Creation Act of 2004” and Staff Position
No. 109-2 (FSP 109-2), “Accounting and Disclosure
Guidance for the Foreign Earnings Repatriation Provision within
the American Jobs Creation Act of 2004”. FSP 109-1
clarifies that the manufacturer’s tax deduction provided
for under the AJCA should be accounted for as a special
deduction in accordance with SFAS No. 109 and not as a tax
rate reduction. FSP 109-2 provides accounting and
disclosure guidance for the repatriation of certain foreign
earnings to a U.S. taxpayer as provided for in the AJCA. We do
not expect that the tax benefits resulting from the AJCA will
have a material impact on our financial statements.
Source of Our Revenues
We derive our revenues from the sale of oil and natural gas that
is produced from our oil and natural gas properties. Revenues
are a function of the volume produced and the prevailing market
prices at the time of sale.
To achieve more predictable cash flows and to reduce our
exposure to downward price fluctuations, we utilize derivative
instruments to hedge future sales prices on a portion of our oil
and natural gas production. Our current strategy is to have up
to 25% of our current monthly-annualized production volumes
hedged over the next twelve months. For example, if our
production volumes for any given month totaled 1 Bcfe, then
our annualized production would be 12 Bcfe. Thus using our
strategy, we could have up to 3 Bcfe of our production over
the next twelve months hedged. The use of certain types
derivative instruments may prevent us from realizing the benefit
of upward price movements.
Components of Our Cost Structure
|
|
|
| |
• |
Production Costs are the day-to-day costs incurred to
bring hydrocarbons out of the ground and to the market together
with the daily costs incurred to maintain our producing
properties. This includes lease operating expenses and
production taxes. |
|
|
|
| |
— |
Lease operating expenses are generally comprised of several
components including the cost of labor and supervision to
operate 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. Lease operating expenses also include the cost for
expensed workovers. 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. |
| |
| |
— |
Lease operating expenses also include ad valorem taxes, which
are imposed by local taxing authorities such as school
districts, cities, and counties or boroughs. The amount of the
tax is based on a percent of value of the property assessed or
determined by the taxing authority on an annual basis. When oil
and natural gas commodity prices rise, the value of our
underlying property interests increase. This results in higher
ad valorem 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 realized at the |
31
|
|
|
| |
|
wellhead 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 natural 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. |
|
|
|
| |
• |
Depreciation, Depletion and Amortization is the
systematic expensing of the capital costs incurred to acquire,
explore and develop natural gas and oil. As a full cost company,
we capitalize all direct costs associated with our exploration
and development efforts, including interest and certain general
and administrative costs, and apportion these costs to each unit
of production sold through depletion expense. Generally, if
reserve quantities are revised up or down, our depletion rate
per unit of production will change inversely. When the
depreciable base increases or decreases, the depletion rate will
move in the same direction. |
| |
| |
• |
Asset Retirement Accretion Expense is the systematic,
monthly accretion of future abandonment costs of tangible assets
such as wells, service assets, pipelines, and other facilities. |
| |
| |
• |
General and Administrative is our overhead, and includes
payroll and benefits for our corporate staff, costs of
maintaining our headquarters, managing our production and
development operations and legal compliance. We capitalize
general and administrative costs directly related to our
exploration and development activities. |
| |
| |
• |
Interest. We rely on our senior credit facility to fund
our short-term liquidity (working capital) and our long-term
financing needs. As a result, we incur interest expense that
correlates to both fluctuations in interest rates and to the
extent that our cash flows from operations do not exceed our
spending. We expect to continue to incur interest expense as we
continue to grow. We capitalize interest directly related to our
unevaluated properties and certain properties under development,
which are not being amortized. |
| |
| |
• |
Income Taxes. We are generally subject to a 35% federal
income tax rate. For income tax purposes, we are allowed
deductions for accelerated depreciation, depletion and
intangible drilling costs that reduce our current tax liability.
Through 2004, all of our income taxes are deferred. |
Capital Commitments
Our primary needs for cash are to fund our capital expenditure
program, fund working capital and the repayment of contractual
obligations. 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 oil and natural gas reserves. Funding for the
exploration and development of oil and gas properties and the
repayment of our 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 “— Contractual Obligations” and
“— Capital Resources.” Cash flows from
operations and the unused committed borrowing capacity under our
senior credit facility fund our working capital obligations. 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.
32
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 expenditure program includes
the following:
|
|
|
| |
• |
cost of acquiring and maintaining our lease acreage position and
our seismic resources; |
| |
| |
• |
cost of drilling and completing new oil and natural gas wells; |
| |
| |
• |
cost of installing new production infrastructure; |
| |
| |
• |
cost of maintaining, repairing and enhancing existing oil and
natural gas wells; |
| |
| |
• |
cost related to plugging and abandoning unproductive or
uneconomic wells; and, |
| |
| |
• |
indirect costs related to our exploration activities, including
payroll and other expenses attributable our exploration
professional staff. |
Our budgeted capital expenditures for 2005 are as follows.
| |
|
|
|
|
| |
|
2005 | |
| |
|
| |
| |
|
(In thousands) | |
|
Drilling
|
|
$ |
70,308 |
|
|
Net land and seismic
|
|
|
13,065 |
|
|
Capitalized interest and G&A
|
|
|
6,184 |
|
|
Other assets
|
|
|
615 |
|
| |
|
|
|
|
Total
|
|
$ |
90,172 |
|
| |
|
|
|
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 all our
budgeted 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
$39.2 million to drill 50 exploratory wells, which
represents 24% of our total capital expenditures for oil and
natural gas activities during that time period. For 2005, we
currently plan to spend approximately $34.7 million, or 38%
of our total budgeted capital expenditures to drill 17
exploratory wells and to drill and complete wells that were in
progress at December 31, 2004. 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 stockholders.
Over the past three years we have spent approximately
$83.9 million to drill 70 development wells and on other
various development activities, which represents 52% of our
total capital expenditures for oil and natural gas activities
during that time period. Due to our exploratory drilling
success, over the last five years, a growing percentage of our
capital expenditures have been allocated to the development of
past field discoveries. For 2005, we currently plan to spend
approximately $35.6 million, or 39% of our total budgeted
capital expenditures on development activities, which include
the drilling of 20 development wells. We currently plan to
allocate approximately $26.5 million of this capital to
develop our proved undeveloped reserves at December 31,
2004.
To support our prospect generation activities, we allocate a
portion of our capital expenditures to land and seismic. Over
the past three years we have spent $22.1 million for land
and seismic which represents
33
14% of our total capital expenditures for oil and natural gas
activities during that time period. For 2005, we expect to spend
approximately $13.1 million or 14% of our total capital
expenditures on land and seismic activities.
Additionally, we currently plan to capitalize approximately
$6.2 million of our forecasted total general and
administrative cost and forecasted interest in 2005.
The final determination with respect to our 2005 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.
For a more in depth discussion of our 2005 capital expenditure
plan see “Item 2. Properties.”
Statements in this section include forward-looking statements.
See “— Forward-Looking Statements.”
The following schedule summarizes our known contractual cash
obligations at December 31, 2004 and the effect such
obligations are expected to have on our liquidity and cash flow
in future periods.
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Payments Due by Year |
| |
|
|
| |
|
Total |
|
|
|
2007- |
|
2009 and |
| |
|
Outstanding |
|
2005 |
|
2006 |
|
2008 |
|
Thereafter |
| |
|
|
|
|
|
|
|
|
|
|
| |
|
(In thousands) |
|
Debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior credit facility
|
|
$ |
21,000 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
21,000 |
|
|
Senior subordinated notes
|
|
|
20,000 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
20,000 |
|
|
Mandatorily redeemable, Series A preferred stock
|
|
|
9,520 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
9,520 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
50,520 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
50,520 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other commitments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest, senior credit facility(a)
|
|
$ |
3,361 |
|
|
$ |
800 |
|
|
$ |
796 |
|
|
$ |
1,591 |
|
|
$ |
174 |
|
|
Interest, senior subordinated notes(b)
|
|
|
6,422 |
|
|
|
1,522 |
|
|
|
1,522 |
|
|
|
3,044 |
|
|
|
334 |
|
|
Dividend Mandatorily redeemable, Series A preferred stock(c)
|
|
|
3,331 |
|
|
|
571 |
|
|
|
571 |
|
|
|
1,142 |
|
|
|
1,047 |
|
|
Non-cancelable operating leases(d)
|
|
|
5,326 |
|
|
|
692 |
|
|
|
709 |
|
|
|
1,385 |
|
|
|
2,540 |
|
|
Asset Retirement Obligations
|
|
|
2,896 |
|
|
|
242 |
|
|
|
172 |
|
|
|
302 |
|
|
|
2,180 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
21,336 |
|
|
$ |
3,827 |
|
|
$ |
3,770 |
|
|
$ |
7,464 |
|
|
$ |
6,275 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Calculation assumes $21 million outstanding under our
senior credit facility, our senior credit facility matures on
March 21, 2009 and the following interest rate assumptions. |
| |
|
|
|
• We paid an interest rate of 4.16% through
January 20, 2005. This was the interest rate that we paid
on borrowings outstanding under our senior credit facility at
December 31, 2004, and the interest rate we paid prior to
amending and restating our senior credit agreement on
January 21, 2005. |
34
|
|
|
|
|
|
• We pay an interest rate of 3.79% from
January 21, 2005 through maturity on March 21, 2009.
This is the interest rate that we are required to pay on
borrowings under our amended and restated senior credit
facility. It was calculated assuming that we utilized
approximately 31% of our available borrowing base and a weighted
average Eurodollar rate of 2.41% plus a margin of 1.375%. This
is the weighted average Eurodollar rate we used to calculate the
interest that we paid on borrowings outstanding under senior
credit facility at December 31, 2004. The amount of
interest that we pay on borrowings under our senior credit
facility 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 — Interest Rate Risk.” |
| |
|
(b) |
|
Calculated assuming $20 million outstanding, an interest
rate of 7.61% and the notes mature on March 21, 2009. The
interest rate on our subordinated notes is fixed using an
interest rate swap. |
| |
|
(c) |
|
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 on October 31, 2005. |
| |
|
|
|
Calculated assuming $9.5 million outstanding, that we elect
to pay the dividends in cash at a rate 6% per annum and the
mandatorily redeemable Series A preferred stock matures on
October 31, 2010. |
| |
|
|
|
If we elect to pay the dividends in kind, we would be required
to issue approximately 32,476 shares of additional Series A
preferred and pay approximately $101,269 in cash to pay
dividends of $750,789 in 2005. This represents dividends on our
outstanding Series A preferred stock from January 1,
2005 to October 31, 2005, the date our option to pay
dividends in kind expires, and two months of cash dividends at
6%. Thereafter, we would be required to pay an annual cash
dividend of approximately $610,000 until maturity. |
| |
|
(d) |
|
Not reduced by rental payments that we will receive from a
non-cancelable sublease of approximately $69,000 due in 2005 and
$44,000 due in 2006. |
As of December 31, 2004, we had $21 million in
borrowings outstanding under our senior credit facility. On
January 21, 2005, we amended and restated our
$80 million senior credit facility to provide up to
$100 million in borrowing capacity and to extend the
maturity of our senior credit facility from March 21, 2006
to March 21, 2009. Our committed borrowing base under our
senior credit facility, which did not change with the amended
and restated facility, at December 31, 2004, was $68.5
million.
Our borrowing base is subject to redetermination at least
semi-annually using the administrative agent and lenders’
usual and customary criteria for oil and gas reserve valuation.
While we do not expect the amount that we have borrowed under
our senior credit facility to exceed our borrowing base, in the
event that our borrowing base is adjusted below the amount that
we have borrowed, we have a period of six months to reduce our
outstanding debt to the borrowing base available with a
requirement to provide additional borrowing base assets or pay
down one-sixth of the excess during each of the six months.
The interest rate we pay on borrowings outstanding under our
senior credit facility is based on Eurodollar (LIBOR) or
Base Rate (Prime) indications, plus a margin. These margins are
subject to change as the percentage of the available borrowing
base that we utilize changes. We are also required to pay a
quarterly commitment fee on the average daily-unused portion of
our borrowing base. The
35
commitment fees we pay are subject to change as the percentage
of our available borrowing base that we utilize changes. The
margins and commitment fees that we pay are as follows:
| |
|
|
|
|
|
|
|
|
|
|
|
|
| Percent of |
|
Eurodollar |
|
Base |
|
|
| Borrowing Base |
|
Rate |
|
Rate |
|
Commitment |
| Utilized |
|
Advances |
|
Advances |
|
Fees |
| |
|
|
|
|
|
|
|
< 25%
|
|
|
1.250 |
% |
|
|
0.250 |
% |
|
|
0.250 |
% |
|
£ 25% and <
50%
|
|
|
1.375 |
% |
|
|
0.375 |
% |
|
|
0.250 |
% |
|
£ 50% and <
75%
|
|
|
1.625 |
% |
|
|
0.625 |
% |
|
|
0.375 |
% |
|
£ 75% and <
90%
|
|
|
1.875 |
% |
|
|
0.875 |
% |
|
|
0.375 |
% |
|
£ 90%
|
|
|
2.000 |
% |
|
|
1.000 |
% |
|
|
0.500 |
% |
Our senior credit facility also contains customary restrictions,
which includes, among others, restrictions on liens,
restrictions on incurring other indebtedness, restrictions on
mergers, restrictions on investments, and restrictions on
hedging activity of a speculative nature or with counterparties
having credit ratings below specified levels.
We are required to maintain a current ratio of at least 1 to 1
and an interest coverage ratio for the four most recent quarters
of at least 3 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. If we should
fail to perform our obligations under these and other covenants,
our senior credit commitment could be terminated and any
outstanding borrowings under our facility could be declared
immediately due and payable. Our current ratio at
December 31, 2004 and interest coverage ratio for the
twelve-month period ending December 31, 2004, were 1.7 to 1
and 18.4 to 1, respectively. As December 31, 2004, and for
the year then ended, we were in compliance with all covenant
requirements in connection with our senior credit facility.
A provision was added to our new senior credit agreement giving
us the option to increase the aggregate commitment amount from
the current $100 million to an amount not to exceed
$200 million. Either new institutions, which the
administrative agent must approve, or existing institutions may
hold this additional commitment. Our senior credit agreement
also permits letters of credit up to the lesser of
$5 million or the unused committed borrowing base.
Issuances of letters of credit reduce the amount of borrowings
available to us under our senior credit facility.
We strive to manage the borrowings outstanding under our senior
credit facility in order to maintain excess borrowing capacity.
As of March 31, 2005, we had $38.1 million of
borrowings outstanding and $30.4 million of additional
borrowing capacity under our senior credit facility.
The future amounts of debt that we borrow under our senior
credit facility is dependent primarily on net cash provided by
operating activities, proceeds from other financing activities,
proceeds generated from alternative financings and proceeds
generated from asset dispositions.
See “ — Analysis of Changes in Cash & Cash
Equivalents — Analysis of changes in cash flows from
financing activities — Senior Credit Facility”
for explanation of prior year changes in our outstanding debt
balance under our senior credit facility.
|
|
| |
Senior Subordinated Notes |
As of December 31, 2004, we had $20 million of senior
subordinated notes outstanding. On January 21, 2005, we
amended and restated our senior subordinated credit agreement in
order to reduce the interest rate that we pay on borrowings
outstanding under the subordinated credit agreement and have the
covenants and other features of the agreement mirror those of
our amended and restated senior credit agreement amended at the
same time. See “ — Senior Credit Facility.”
Prior to amendment, we were required to pay an interest rate
based on the Eurodollar rate (LIBOR), plus a margin of 5.05%. We
also entered into an interest rate swap contract to fix the
coupon that we paid on those borrowings at 8.76%. The interest
rate that we are now required to pay on our subordinated notes
36
is based on the Eurodollar rate (LIBOR), plus a margin of 3.9%.
Using the swap contract, the interest rate is fixed at 7.61%.
Our new interest rate is retroactive back to October 1,
2004. 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.
The senior subordinated notes are secured obligations ranking
junior to our senior credit facility and have covenants similar
to the senior credit facility. We are required to maintain a
current ratio of at least 1 to 1 and an interest coverage ratio
for the four most recent quarters of at least 3 to 1. Our
current ratio at December 31, 2004 and interest coverage
ratio for the twelve-month period ending December 31, 2004,
were 1.7 to 1 and 18.4 to 1, respectively. At December 31,
2004, and for the year then ended, we were in compliance with
all covenant requirements in connection with our senior
subordinated notes.
We are also required to maintain a Total Calculated NPV to Total
Debt Ratio of 1.5 to 1. Total Calculated NPV is the estimated
future cash flows from our reserves using the risked net present
value calculated using discounted at 9% to total debt of 1.5 to
1. As amended, the price assumptions used to determine NPV for
reserves will be based upon the following price decks:
(i) for natural gas, the Gas Strip Price, provided that if
any Gas Strip Price is greater than $4.00 per MMBtu, the price
shall be capped at $4.00 per MMBtu; and (ii) for crude oil,
the Oil Strip Price, provided that if any Oil Strip Price is
greater than $27 per barrel, the price shall be capped at $27
per barrel. Our ratio of risked net present value discounted at
9% to total debt at June 30, 2004, was 2.3 to 1, and was in
compliance with the subordinated notes covenant that requires us
to maintain a ratio of 1.5 to 1.
If we should fail to perform our obligations under these and
other covenants, our senior subordinated notes could be
terminated and could be declared immediately due and payable.
See “ — Analysis of Changes in Cash & Cash
Equivalents — Analysis of changes in cash flows from
financing activities — Senior Subordinated Notes”
for explanation of prior year changes in our outstanding senior
subordinated notes balances.
|
|
| |
Mandatorily Redeemable Preferred Stock |
As of December 31, 2004, we had $9.5 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 on
October 31, 2005. To date, we have satisfied all of the
dividend payments with issuance of additional shares of
Series A preferred stock. Our Series A preferred stock
matures on October 31, 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,
2004, 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 2003 and
dividends that have been paid in kind on this preferred stock.
See “ — Analysis of Changes in Cash & Cash
Equivalents — Analysis of changes in cash flows from
financing activities — Mandatorily Redeemable
Preferred Stock” and “Item 5. Market for
Registrant’s Common Equity and Related Stockholder
Matters — Mandatorily Redeemable Preferred Stock”
for explanation of prior year changes in our outstanding
Mandatorily Redeemable Preferred Stock balances.
|
|
| |
Off Balance Sheet Arrangements |
We currently have operating leases, which are considered off
balance sheet arrangements. 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.
37
Capital Resources
We intend to fund our 2005 capital expenditure program and
contractual commitments through cash flows from operations,
borrowings under our senior credit facility and if required,
alternative financing sources. Our primary sources of cash
during 2004 were funds generated by operations and net proceeds
received from the sale of common stock in July 2004. Cash from
the common stock sale was used for exploration and development
expenditures and to reduce debt under our revolving bank credit
facility. We made aggregate cash payments of $1.6 million
for interest in 2004.
|
|
| |
Net cash provided by operating activities |
Net cash provided by operating activities is a function of the
prices that we receive from the sale of oil and natural gas,
which are inherently volatile and unpredictable, gains or losses
related to hedging, production, operating cost and our cost of
capital. 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. During 2004, 2003 and 2002, net cash
provided by operating activities funded 67%, 90% and in excess
of 100% of our net cash used by investing activities,
respectively. 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.”
As of December 31, 2004, we had $47.5 million of
unused committed borrowing capacity available under our senior
credit facility. Since our borrowing base is redetermined at
least semi-annually, the amount of borrowing capacity available
to us could fluctuate. While we do not expect the amount that we
have borrowed under our senior credit facility to exceed our
borrowing base, in the event that our borrowing base is adjusted
below the amount that we have borrowed, our access to further
borrowings will be reduced, and we may not have the resources
necessary to carry out our planned exploration and development
activities.
Our senior credit facility also contains customary restrictions
and covenants. Should we be unable to comply with these or other
covenants, our senior lenders may be unwilling to waive
compliance or amend the covenants and our liquidity may be
adversely affected. See “ — 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” and “ — Capital
Commitments – Senior Credit Facility.”
When we amended and restated our senior credit facility on
January 21, 2005, a provision was added which gives us the
option to increase the aggregate amount committed from the
current $100 million to an amount not to exceed
$200 million. Either new institutions, which the
administrative agent must approve, or existing institutions may
hold this additional commitment. Our senior credit agreement
also permits letters of credit up to the lesser of
$5 million or the unused committed borrowing base.
Issuances of letters of credit reduce the amount of borrowings
available to us under our senior credit facility.
The future amounts of debt that we borrow under our senior
credit facility is dependent primarily on net cash provided by
operating activities, proceeds from other financing activities
and proceeds generated from asset dispositions.
We strive to manage the borrowings outstanding under our senior
credit facility in order to maintain excess borrowing capacity.
As of March 31, 2005, we had $30.4 million of
additional borrowing capacity under our senior credit facility.
38
|
|
| |
Access to Capital Markets |
We currently have an effective universal shelf registration
statement covering the sale, from time to time, of our common
stock, preferred stock, depositary shares, warrants and debt
securities, or a combination of any of these securities. In July
2004, we sold 2,598,500 shares of our common stock under the
universal shelf registration statement. Following this sale, our
remaining capacity under the shelf registration statement is
approximately $176.9 million. However, our ability to raise
additional capital using our shelf registration statement may be
limited due to overall conditions of the stock market or the oil
and natural gas industry.
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 capital available 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.
The prices we receive for our oil production are based on global
market conditions. Our average sales price for oil in 2004 was
$40.13 per barrel, which was 30% higher and 59% higher than the
price we received in 2003 and 2002, respectively. Significant
factors that will impact 2005 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.
Our average sales price for natural gas in 2004 was $6.05 per
Mcf, which was 7% higher and 82% higher than the price that we
received in 2003 and 2002, respectively. The increase North
American gas prices in 2004 were in response to strong supply
and demand fundamentals. Natural gas prices for 2005 will depend
on variations in key North American gas supply and demand
indicators.
Results of Operations
|
|
| |
Comparison of the twelve-month periods ended
December 31, 2004, 2003 and 2002 |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, |
| |
|
|
| |
|
2004 |
|
% Change |
|
2003 |
|
% Change |
|
2002 |
| |
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
573 |
|
|
|
(20 |
)% |
|
|
720 |
|
|
|
3 |
% |
|
|
701 |
|
|
Natural gas (MMcf)
|
|
|
8,830 |
|
|
|
39 |
% |
|
|
6,356 |
|
|
|
10 |
% |
|
|
5,791 |
|
|
Total (MMcfe)(1)
|
|
|
12,265 |
|
|
|
15 |
% |
|
|
10,674 |
|
|
|
7 |
% |
|
|
9,996 |
|
|
Average daily production (MMcfe/d)
|
|
|
34.1 |
|
|
|
|
|
|
|
29.7 |
|
|
|
|
|
|
|
27.8 |
|
|
|
| (1) |
Mcfe is defined one million cubic feet equivalent of natural
gas, determined using the ratio of six Mcf of natural gas to one
Bbl of crude oil, condensate or natural gas liquids. |
Our net equivalent production volumes for 2004 were 12.3 Bcfe
(34.1 MMcfe/d) compared to 10.7 Bcfe (29.7 MMcfe/d) in 2003. The
increase in our production volumes was due to production growth
from wells that we drilled and completed during the last quarter
of 2003 and during 2004. New production
39
from these wells was partially offset by the natural decline of
existing production. Natural gas represented 72% and 60% of our
total production in 2004 and 2003, respectively. For 2004
compared to 2003, the change in our production volumes was due
to the following.
|
|
|
| |
• |
Production from our Gulf Coast province for 2004 increased 14%
when compared to production from that province in 2003. Gulf
Coast production represented 61% of our total production in 2004
versus 62% in 2003. Natural gas represented approximately 74% of
our total production from the Gulf Coast in 2004 compared to 60%
in 2003. |
| |
| |
• |
Production from our Anadarko Basin province for 2004 increased
46% when compared to production from that province in 2003.
Anadarko Basin production represented 29% of our total
production in 2004 versus 22% in 2003. Natural gas represented
approximately 88% of our total production from the Anadarko
Basin in 2004 compared to 90% in 2003. |
| |
| |
• |
Production from our West Texas province for 2004 decreased 26%
when compared to production from that province in 2003 West
Texas production represented 10% of our total production versus
16% in 2003. Production from our West Texas province is
primarily oil. Oil represented approximately 90% of our total
production from our West Texas province in 2004 versus 84% in
2003. |
Our net equivalent production volumes for 2003 were 10.7 Bcfe
(29.7 MMcfe/d) compared to 10 Bcfe (27.8 MMcfe/d) in 2002.
The increase in our production volumes was due to production
growth from wells that we drilled and completed during the last
quarter of 2002 and during 2003. New production from these wells
was partially offset by the natural decline of existing
production. Natural gas represented 60% and 58% of our total
production in 2003 and 2002, respectively. 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 62% of our total production in 2003
versus 53% in 2002. Natural gas represented approximately 60% of
our 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 22% of our total
production in 2003 versus 26% in 2002. Natural gas represented
approximately 90% of our 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 84% of our total
production from our West Texas province in 2003 versus 89% in
2002. |
40
Hedging, commodity prices and revenues
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 contracts for 2004, 2003 and 2002.
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, |
| |
|
|
| |
|
2004 |
|
% Change |
|
2003 |
|
% Change |
|
2002 |
| |
|
|
|
|
|
|
|
|
|
|
|
Oil swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (MBbls)
|
|
|
73 |
|
|
|
(67 |
%) |
|
|
226 |
|
|
|
78 |
% |
|
|
127 |
|
|
Average swap price ($ per Bbl)
|
|
$ |
24.65 |
|
|
|
1 |
% |
|
$ |
24.51 |
|
|
|
(6 |
%) |
|
$ |
25.96 |
|
|
Gain /(loss) upon settlement ($ in thousands)
|
|
$ |
(1,073 |
) |
|
|
(28 |
%) |
|
$ |
(1,488 |
) |
|
|
424 |
% |
|
$ |
(284 |
) |
| |
|
Oil collars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (MBbls)
|
|
|
179 |
|
|
|
294 |
% |
|
|
45 |
|
|
|
(78 |
%) |
|
|
205 |
|
|
Average floor price ($ per Bbl)
|
|
$ |
24.92 |
|
|
|
38 |
% |
|
$ |
18.00 |
|
|
|
0 |
% |
|
$ |
18.00 |
|
|
Average ceiling price ($ per Bbl)
|
|
$ |
31.21 |
|
|
|
38 |
% |
|
$ |
22.56 |
|
|
|
1 |
% |
|
$ |
22.36 |
|
|
Gain /(loss) upon settlement ($ in thousands)
|
|
$ |
(1,768 |
) |
|
|
345 |
% |
|
$ |
(397 |
) |
|
|
(53 |
%) |
|
$ |
(851 |
) |
| |
|
Total oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (MBbls)
|
|
|
252 |
|
|
|
(8 |
%) |
|
|
271 |
|
|
|
(18 |
%) |
|
|
332 |
|
|
Gain /(loss) upon settlement ($ in thousands)
|
|
$ |
(2,841 |
) |
|
|
51 |
% |
|
$ |
(1,885 |
) |
|
|
66 |
% |
|
$ |
(1,135 |
) |
| |
|
Natural gas swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (MMbtu)
|
|
|
753 |
|
|
|
(72 |
%) |
|
|
2,664 |
|
|
|
(21 |
%) |
|
|
3,359 |
|
|
Average swap price ($ per MMbtu)
|
|
$ |
4.53 |
|
|
|
19 |
% |
|
$ |
3.81 |
|
|
|
22 |
% |
|
$ |
3.13 |
|
|
Gain /(loss) upon settlement ($ in thousands)
|
|
$ |
(1,066 |
) |
|
|
(78 |
%) |
|
$ |
(4,807 |
) |
|
|
575 |
% |
|
$ |
(712 |
) |
| |
|
Natural gas collars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (MMbtu)
|
|
|
2,504 |
|
|
|
NM |
|
|
|
— |
|
|
|
NM |
|
|
|
— |
|
|
Average floor price ($ per MMbtu)
|
|
$ |
4.54 |
|
|
|
NM |
|
|
$ |
— |
|
|
|
NM |
|
|
$ |
— |
|
|
Average ceiling price ($ per MMbtu)
|
|
$ |
6.85 |
|
|
|
NM |
|
|
$ |
— |
|
|
|
NM |
|
|
$ |
— |
|
|
Gain /(loss) upon settlement ($ in thousands)
|
|
$ |
(787 |
) |
|
|
NM |
|
|
$ |
— |
|
|
|
NM |
|
|
$ |
— |
|
| |
|
Natural gas floors
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (MMbtu)
|
|
|
— |
|
|
|
100 |
% |
|
|
1,070 |
|
|
|
NM |
|
|
|
— |
|
|
Average floor price ($ per MMbtu)
|
|
$ |
— |
|
|
|
100 |
% |
|
$ |
4.50 |
|
|
|
NM |
|
|
$ |
— |
|
|
Gain /(loss) upon settlement ($ in thousands)
|
|
$ |
— |
|
|
|
100 |
% |
|
$ |
— |
|
|
|
NM |
|
|
$ |
— |
|
| |
|
Total natural gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (MMbtu)
|
|
|
3,257 |
|
|
|
(13 |
%) |
|
|
3,734 |
|
|
|
11 |
% |
|
|
3,359 |
|
|
Gain /(loss) upon settlement ($ in thousands)
|
|
$ |
(1,853 |
) |
|
|
(61 |
%) |
|
$ |
(4,807 |
) |
|
|
575 |
% |
|
$ |
(712 |
) |
Reported revenues from the sale of oil and natural gas are based
on the market price we receive for our commodities, adjusted for
marketing charges and the results from the settlement of our
derivative commodity contracts that qualify for cash flow hedge
accounting treatment under SFAS 133.
We utilize commodity swap, collar, three way costless 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 — Derivative Instruments and Hedging
Activities — Commodity Price Risk” for a
description of our derivative commodity contracts and our open
derivative commodity contracts.
The effective portions of changes in the fair values of our
derivative commodity contracts that qualify for cash flow hedge
accounting treatment under SFAS 133 are recorded as increases or
decreases to
41
stockholders’ equity until the underlying contract is
settled. Consequentially, changes in the effective portions of
these derivative contracts add volatility to our reported
stockholders’ equity until the contract is settled or is
terminated. See “Notes to the Consolidated Financial
Statements — Note 2.”
Gains or losses related to the settlement and the changes in the
fair values of our derivative commodity contracts that do not
qualify for cash flow hedge accounting treatment under
SFAS 133 are recognized in other income (expense).
See “Item 7A. Quantitative and Qualitative Disclosures
About Market Risk — Derivative Instruments and Hedging
Activities — Commodity Price Risk” for our open
derivative commodity contracts.
Commodity prices and revenues
The following table shows our revenue from the sale of oil and
natural gas for 2004, 2003 and 2002.
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, |
| |
|
|
| |
|
2004 |
|
% Change |
|
2003 |
|
% Change |
|
2002 |
| |
|
|
|
|
|
|
|
|
|
|
| |
|
(In thousands, except per unit measurements) |
|
Revenue from the sale of oil and natural gas:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
$ |
22,976 |
|
|
|
4 |
% |
|
$ |
22,157 |
|
|
|
26 |
% |
|
$ |
17,644 |
|
|
Gain (loss) due to hedging
|
|
|
(2,841 |
) |
|
|
51 |
% |
|
|
(1,885 |
) |
|
|
66 |
% |
|
|
(1,135 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Total revenue from the sale of oil
|
|
$ |
20,135 |
|
|
|
(1 |
%) |
|
$ |
20,272 |
|
|
|
23 |
% |
|
$ |
16,509 |
|
| |
|
Natural gas sales
|
|
$ |
53,431 |
|
|
|
48 |
% |
|
$ |
36,080 |
|
|
|
87 |
% |
|
$ |
19,303 |
|
|
Gain (loss) due to hedging
|
|
|
(1,853 |
) |
|
|
(61 |
%) |
|
|
(4,807 |
) |
|
|
575 |
% |
|
|
(712 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Total revenue from the sale of natural gas
|
|
$ |
51,578 |
|
|
|
65 |
% |
|
$ |
31,273 |
|
|
|
68 |
% |
|
$ |
18,591 |
|
| |
|
Oil and natural gas sales
|
|
$ |
76,407 |
|
|
|
31 |
% |
|
$ |
58,237 |
|
|
|
58 |
% |
|
$ |
36,947 |
|
|
Gain (loss) due to hedging
|
|
|
(4,694 |
) |
|
|
(30 |
%) |
|
|
(6,692 |
) |
|
|
262 |
% |
|
|
(1,847 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Total revenue from the sale of oil and natural gas
|
|
$ |
71,713 |
|
|
|
39 |
% |
|
$ |
51,545 |
|
|
|
47 |
% |
|
$ |
35,100 |
|
| |
|
Average prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales price (per Bbl)
|
|
$ |
40.13 |
|
|
|
30 |
% |
|
$ |
30.79 |
|
|
|
22 |
% |
|
$ |
25.17 |
|
|
Gain (loss) due to hedging (per Bbl)
|
|
|
(4.96 |
) |
|
|
89 |
% |
|
|
(2.62 |
) |
|
|
62 |
% |
|
|
(1.62 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Realized oil price (per Bbl)
|
|
$ |
35.17 |
|
|
|
25 |
% |
|
$ |
28.17 |
|
|
|
20 |
% |
|
$ |
23.55 |
|
| |
|
Natural gas sales price (per Mcf)
|
|
$ |
6.05 |
|
|
|
7 |
% |
|
$ |
5.68 |
|
|
|
71 |
% |
|
$ |
3.33 |
|
|
Gain (loss) due to hedging (per Mcf)
|
|
|
(0.21 |
) |
|
|
(72 |
%) |
|
|
(0.76 |
) |
|
|
533 |
% |
|
|
(0.12 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Realized natural gas price (per Mcf)
|
|
$ |
5.84 |
|
|
|
19 |
% |
|
$ |
4.92 |
|
|
|
53 |
% |
|
$ |
3.21 |
|
| |
|
Natural gas equivalent sales price (per Mcfe)
|
|
$ |
6.23 |
|
|
|
14 |
% |
|
$ |
5.46 |
|
|
|
48 |
% |
|
$ |
3.70 |
|
|
Gain (loss) due to hedging (per Mcfe)
|
|
|
(0.38 |
) |
|
|
(40 |
%) |
|
|
(0.63 |
) |
|
|
232 |
% |
|
|
(0.19 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Realized natural gas equivalent (per Mcfe)
|
|
$ |
5.85 |
|
|
|
21 |
% |
|
$ |
4.83 |
|
|
|
38 |
% |
|
$ |
3.51 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
| |
|
2003 |
|
2002 |
| |
|
to 2004 |
|
to 2003 |
| |
|
|
|
|
|
Change in revenue from the sale of oil
|
|
|
|
|
|
|
|
|
|
Price variance impact
|
|
$ |
5,348 |
|
|
$ |
4,044 |
|
|
Volume variance impact
|
|
|
(4,529 |
) |
|
|
469 |
|
|
Cash settlement of hedging contracts
|
|
|
(956 |
) |
|
|
(750 |
) |
| |
|
|
|
|
|
|
|
|
| |
Total change
|
|
$ |
(137 |
) |
|
$ |
3,763 |
|
| |
|
|
|
|
|
|
|
|
42
| |
|
|
|
|
|
|
|
|
|
| |
|
2003 | |
|
2002 | |
| |
|
to 2004 | |
|
to 2003 | |
| |
|
| |
|
| |
|
Change in revenue from the sale of natural gas
|
|
|
|
|
|
|
|
|
|
Price variance impact
|
|
$ |
3,275 |
|
|
$ |
14,914 |
|
|
Volume variance impact
|
|
|
14,076 |
|
|
|
1,863 |
|
|
Cash settlement of hedging contracts
|
|
|
2,954 |
|
|
|
(4,095 |
) |
| |
|
|
|
|
|
|
| |
Total change
|
|
$ |
20,305 |
|
|
$ |
12,682 |
|
| |
|
|
|
|
|
|
Our revenues from the sale of oil and natural gas for 2004
increased 39% over revenues in 2003. The change in revenues was
due to the following:
|
|
|
| |
• |
Approximately $9.6 million of the increase in revenue from
the sale oil and natural gas was due to a 15% increase in our
production volumes; |
| |
| |
• |
Approximately $8.6 million of the increase was due to an
increase in the sales price we received for oil and natural gas;
and |
| |
| |
• |
Approximately $2 million of the increase was due a decrease
in losses due to the cash settlement of derivative commodity
contracts. |
Our revenues from the sale of oil and natural gas for 2003
increased 47% over revenues in 2002. The change in revenue was
due to the following:
|
|
|
| |
• |
Approximately $18.9 million of the increase in oil and
natural gas sales was due to a $1.76 Mcfe increase in the sales
price we received for oil and natural gas; |
| |
| |
• |
Approximately $2.4 million of the increase in oil and
natural gas sales was due to an increase in our production
volumes; and, |
| |
| |
• |
These increases were offset by an increase in losses due to the
cash settlement of derivative commodity contracts of
$4.9 million. |
Other revenue. Other revenue relates to fees that we
charge other parties who use our gas gathering systems that we
own to move their production from the wellhead to third party
gas pipeline systems. Other revenue for 2004 was $515,000
compared to $132,000 in 2003 and $76,000 in 2002. Costs related
to our gas gathering systems are recorded in lease operating
expenses.
Operating costs and expenses
Production costs. Production costs include lease
operating expenses and production taxes.
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, |
| |
|
|
| |
|
2004 |
|
% Change |
|
2003 |
|
% Change |
|
2002 |
| |
|
|
|
|
|
|
|
|
|
|
| |
|
(In thousands, except per unit measurements) |
|
Production cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating & maintenance
|
|
$ |
4,480 |
|
|
|
31 |
% |
|
$ |
3,420 |
|
|
|
25 |
% |
|
$ |
2,738 |
|
|
Expensed workovers
|
|
|
878 |
|
|
|
(22 |
)% |
|
|
1,123 |
|
|
|
174 |
% |
|
|
410 |
|
|
Ad valorem taxes
|
|
|
815 |
|
|
|
24 |
% |
|
|
657 |
|
|
|
8 |
% |
|
|
611 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Total lease operating expenses
|
|
$ |
6,173 |
|
|
|
19 |
% |
|
$ |
5,200 |
|
|
|
38 |
% |
|
$ |
3,759 |
|
|
Production taxes
|
|
|
3,107 |
|
|
|
25 |
% |
|
|
2,477 |
|
|
|
25 |
% |
|
|
1,977 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Total production expenses
|
|
$ |
9,280 |
|
|
|
21 |
% |
|
$ |
7,677 |
|
|
|
34 |
% |
|
$ |
5,736 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
43
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, | |
| |
|
| |
| |
|
2004 | |
|
% Change | |
|
2003 | |
|
% Change | |
|
2002 | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
| |
|
(In thousands, except per unit measurements) | |
|
Production cost ($ per Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating & maintenance
|
|
$ |
0.36 |
|
|
|
13 |
% |
|
$ |
0.32 |
|
|
|
14 |
% |
|
$ |
0.28 |
|
|
Expensed workovers
|
|
|
0.07 |
|
|
|
(36 |
)% |
|
|
0.11 |
|
|
|
175 |
% |
|
|
0.04 |
|
|
Ad valorem taxes
|
|
|
0.07 |
|
|
|
17 |
% |
|
|
0.06 |
|
|
|
0 |
% |
|
|
0.06 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Total lease operating expenses
|
|
$ |
0.50 |
|
|
|
2 |
% |
|
$ |
0.49 |
|
|
|
29 |
% |
|
$ |
0.38 |
|
|
Production taxes
|
|
|
0.25 |
|
|
|
9 |
% |
|
|
0.23 |
|
|
|
15 |
% |
|
|
0.20 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Total production expenses
|
|
$ |
0.75 |
|
|
|
4 |
% |
|
$ |
0.72 |
|
|
|
24 |
% |
|
$ |
0.58 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The primary reason for the overall increase in our production
costs over the past three years has been due to an increase in
number of producing wells. In the future we anticipate that our
total production cost will increase as we add new wells and
production facilities and continue to maintain production from
existing maturing properties. Changes in commodity prices will
also have an affect on ad valorem taxes and production taxes. We
believe that per unit of production measures are the best way to
evaluate our production cost information. We use this
information to evaluate our performance relative to our peers
and to internally evaluate our performance.
For 2004, our unit production cost increased 4% when compared to
2003. The change in our 2004 unit production cost was due to the
following:
|
|
|
| |
• |
An increase in costs for compressor rental and maintenance and
saltwater disposal were the primary reasons for the increase in
our operating and maintenance expense; |
| |
| |
• |
Ad valorem taxes increased due to higher oil and natural gas
prices during 2003; |
| |
| |
• |
Production taxes for 2004 were $0.02 higher due to an increase
in the sales price that we received for our oil and natural gas.
Our effective production tax rate in 2004 was 4.1% of pre-hedge
oil and natural gas sales revenue, compared to 4.3% in 2003; and |
| |
| |
• |
A decrease in the number of expensed workovers partially offset
these increases. |
For 2003, our unit production cost increased 24% when compared
to 2002. The change in our 2003 unit production cost was 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; |
| |
| |
• |
Production taxes for 2003 were $0.03 higher due to an increase
in the sales price that we received for our 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. |
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.
44
The cost of a technical employee includes associated technical
organization costs such as supervision, telephone and postage.
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, |
| |
|
|
| |
|
2004 |
|
% Change |
|
2003 |
|
% Change |
|
2002 |
| |
|
|
|
|
|
|
|
|
|
|
| |
|
(In thousands, except per unit measurements) |
|
General and administrative cost
|
|
$ |
10,264 |
|
|
|
13 |
% |
|
$ |
9,121 |
|
|
|
(0 |
%) |
|
$ |
9,191 |
|
|
Capitalized general and administrative cost
|
|
|
(4,872 |
) |
|
|
5 |
% |
|
|
(4,621 |
) |
|
|
10 |
% |
|
|
(4,220 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expense
|
|
$ |
5,392 |
|
|
|
20 |
% |
|
$ |
4,500 |
|
|
|
(9 |
%) |
|
$ |
4,971 |
|
|
General and administrative expense ($ per Mcfe)
|
|
$ |
0.44 |
|
|
|
5 |
% |
|
$ |
0.42 |
|
|
|
(16 |
%) |
|
$ |
0.50 |
|
For 2004 compared to 2003, our general and administrative
expenses increased by 20%. The changes in general and
administrative expenses for 2004 were primarily due to the
following:
|
|
|
| |
• |
We paid approximately $399,000 to outside consultants and our
independent public accountants for the implementation of
Section 404 of Sarbanes-Oxley. We expect these cost to
decrease approximately 50% in 2005; |
| |
| |
• |
We paid $242,000 related to the settlement of a legal dispute
over the ownership of a well; and |
| |
| |
• |
Increases in payroll and benefits expense, fees paid to outside
reserve engineers, franchise taxes and corporate insurance were
the other primary reasons for the increase in general &
administrative expenses. |
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; and |
| |
| |
• |
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. |
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. The historical financial information in this section
pertaining to depletion expense and accumulated depletion that
are part of our net proved oil and natural gas properties has
been restated, as further discussed in Item 8, Financial
Statements and Supplementary Data, Note 2.
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, |
| |
|
|
| |
|
2004 |
|
% Change |
|
2003 |
|
% Change |
|
2002 |
| |
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
Restated |
|
|
|
Restated |
| |
|
(In thousands, except per unit measurements) |
|
Depletion of oil and natural gas properties
|
|
$ |
23,844 |
|
|
|
42 |
% |
|
$ |
16,819 |
|
|
|
14 |
% |
|
$ |
14,694 |
|
|
Depletion of oil and natural gas properties per Mcfe
|
|
$ |
1.94 |
|
|
|
23 |
% |
|
$ |
1.58 |
|
|
|
7 |
% |
|
$ |
1.47 |
|
Approximately 36% of the increase in our depletion expense for
2004 was due to a 15% increase in production volumes. The
remaining 64% of the increase was due to an increase in our
depletion rate. Our depletion rate increased as a result of
downward reserve revisions related to disappointing drilling
results
45
related to two proved undeveloped wells that were drilled in
2004 at our Mills Ranch and Floyd Fault Block fields, and a
decline in performance of our Floyd South Field and in certain
West Texas water drive wells.
For 2005, based on our reserve base at December 31, 2004,
we expect our depletion rate to be $2.39 per Mcfe.
For 2003 compared to 2002, a $0.11 increase in our
depletion rate accounted for approximately $1.1 million of
the increase in our total depletion expense and increased
production volumes accounted for approximately $997,000 of the
increase. The increase in our 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.
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, | |
| |
|
| |
| |
|
2004 | |
|
% Change | |
|
2003 | |
|
% Change | |
|
2002 | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
| |
|
(In thousands) | |
|
Interest on senior credit facility
|
|
$ |
882 |
|
|
|
(47 |
%) |
|
$ |
1,674 |
|
|
|
(54 |
%) |
|
$ |
3,636 |
|
|
Interest on senior subordinated notes
|
|
|
1,703 |
|
|
|
(28 |
%) |
|
|
2,369 |
|
|
|
6 |
% |
|
|
2,243 |
|
|
Commitment fees
|
|
|
236 |
|
|
|
61 |
% |
|
|
147 |
|
|
|
4,800 |
% |
|
|
3 |
|
|
Dividend on mandatorily redeemable preferred stock
|
|
|
726 |
|
|
|
114 |
% |
|
|
340 |
|
|
|
NM |
|
|
|
— |
|
|
Amortization of deferred loan and debt issuance cost
|
|
|
766 |
|
|
|
(27 |
%) |
|
|
1,053 |
|
|
|
(12 |
%) |
|
|
1,190 |
|
|
Other general interest expense
|
|
|
26 |
|
|
|
(48 |
%) |
|
|
50 |
|
|
|
14 |
% |
|
|
44 |
|
|
Capitalized interest expense
|
|
|
(1,195 |
) |
|
|
46 |
% |
|
|
(818 |
) |
|
|
(7 |
%) |
|
|
(878 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Net interest expense
|
|
$ |
3,144 |
|
|
|
(35 |
%) |
|
$ |
4,815 |
|
|
|
(23 |
%) |
|
$ |
6,238 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average debt outstanding
|
|
$ |
56,352 |
|
|
|
(21 |
%) |
|
$ |
71,392 |
|
|
|
(25 |
%) |
|
$ |
95,562 |
|
|
Average interest rate on outstanding indebtedness(a)
|
|
|
6.3 |
% |
|
|
|
|
|
|
6.3 |
% |
|
|
|
|
|
|
6.2 |
% |
|
|
| (a) |
Calculated as the sum of the interest expense on our outstanding
indebtedness, commitment fees that we pay on unused borrowing
capacity and the dividend on our mandatorily redeemable
preferred stock divided by the weighted average debt and
preferred stock outstanding for the period. |
Our net interest expense for 2004 was 35% lower than net
interest expense in 2003. The following were the primary reasons
for the change in our 2004 net interest expense.
|
|
|
| |
• |
The average interest rate that we paid on borrowings drawn under
our senior credit facility was lower because we utilized a
smaller percentage of our available borrowing base during 2004.
Our weighted average debt outstanding under our senior credit
facility during 2004 represented approximately 40% of our
available borrowing base, compared to 66% in 2003. This decrease
was partially offset by a 61% increase in the commitment fees
that we paid on the unused portion of our borrowing base during
2004. |
| |
| |
• |
A 114% increase in the dividends that we paid on our mandatorily
redeemable preferred stock due to 2004 includes a full year of
dividends whereas 2003 only includes dividends for half the year
due to the adoption of SFAS 150 in July 2003. |
| |
| |
• |
The amount of interest that we capitalized during 2004 increased
due to an increase in our unevaluated property balance
throughout the year. Approximately $200,000 of our capitalized
interest in 2004 was related to the Mills Ranch #2-98
exploration well that was drilling at December 31, 2004. |
46
|
|
|
| |
• |
A 28% decrease in the interest we paid on our senior
subordinated notes due to a 10% decrease in the weighted average
notes outstanding during the period combined with a decrease in
the interest rate that we paid on the outstanding notes. |
Our net interest expense for 2003 was 23% lower than net
interest expense in 2002. The following were the primary reasons
for the change in our 2003 net interest expense.
|
|
|
| |
• |
The average interest rate that we paid on borrowings drawn under
our senior credit facility was lower because we utilized a
smaller percentage of our available borrowing base during 2003.
Our weighted average debt balance drawn under our senior credit
facility during 2003 represented approximately 66% of our
available borrowing base, compared to 100% in 2002. We also paid
a lower interest rate on borrowings under our senior credit
facility due to the amendment in March 2003. This decrease was
partially offset because we had to pay commitment fees on the
unused portion of our borrowing base during 2003. See
“— Capital Commitments — Contractual
Obligations” and “Item 7A Quantitative and
Qualitative Disclosures About Market Risk — 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 million in
2002 to $22.2 million in 2003. Our outstanding senior
subordinated notes balance increased because a portion of the
2003 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
“— Analysis of Changes In Cash and Cash
Equivalents — Analysis of changes in cash flows from
financing activities — 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. |
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, |
| |
|
|
| |
|
2004 |
|
% Change |
|
2003 |
|
% Change |
|
2002 |
| |
|
|
|
|
|
|
|
|
|
|
| |
|
(In thousands) |
|
Non-cash gain (loss) due to change in fair market value of
derivative contracts that did not qualify as cashflow hedge
under SFAS 133
|
|
$ |
(33 |
) |
|
|
NM |
|
|
$ |
— |
|
|
|
(100 |
%) |
|
$ |
384 |
|
|
Non-cash gain (loss) for ineffective portion of cash flow hedges
|
|
|
658 |
|
|
|
NM |
|
|
|
(455 |
) |
|
|
265 |
% |
|
|
(122 |
) |
|
Cash loss on settlement of derivative contracts that did not
qualify as hedges
|
|
|
— |
|
|
|
0 |
% |
|
|
— |
|
|
|
100 |
% |
|
|
(559 |
) |
|
Gain on investments
|
|
|
117 |
|
|
|
NM |
|
|
|
— |
|
|
|
(100 |
%) |
|
|
21 |
|
|
Other
|
|
|
— |
|
|
|
100 |
% |
|
|
(146 |
) |
|
|
329 |
% |
|
|
(34 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Other income (loss)
|
|
$ |
742 |
|
|
|
NM |
|
|
$ |
(601 |
) |
|
|
94 |
% |
|
$ |
(310 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
47
The following table shows the volumes and the weighted average
NYMEX reference price for those volumes for our derivative
commodity contracts that we did not designate as cash flow
hedges under SFAS 133 in 2004, 2003 and 2002.
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, |
| |
|
|
| |
|
2004 |
|
% Change |
|
2003 |
|
% Change |
|
2002 |
| |
|
|
|
|
|
|
|
|
|
|
|
Natural gas caps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (MMbtu)
|
|
|
— |
|
|
|
0 |
% |
|
|
— |
|
|
|
(100 |
%) |
|
|
1,810,000 |
|
|
Average ceiling price ($ per MMbtu)
|
|
$ |
— |
|
|
|
0 |
% |
|
$ |
— |
|
|
|
(100 |
%) |
|
$ |
2.63 |
|
|
Written puts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (MMbtu)
|
|
|
140,000 |
|
|
|
NM |
|
|
|
— |
|
|
|
0 |
% |
|
|
— |
|
|
Average ceiling price ($ per MMbtu)
|
|
$ |
5.50 |
|
|
|
NM |
|
|
$ |
— |
|
|
|
0 |
% |
|
$ |
— |
|
See “Item 7A. Quantitative and Qualitative Disclosures
About Market Risk — Derivative Instruments and Hedging
Activities — Commodity Price Risk” for a
description of our derivative commodity contracts and our open
derivative commodity contracts.
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 taxes: A deferred tax liability or asset is
recognized for the estimated future tax effects attributable to
(i) NOLs and (ii) existing temporary differences
between book and taxable income. Realization of net deferred tax
assets is dependent upon generating sufficient taxable income
within the carryforward period available under tax law.
Prior to 2003, we believed that it was more likely than not that
our net deferred tax assets would not be realized and,
therefore, reflected a comparable valuation allowance. In 2003,
we recognized a net deferred tax asset of $1.8 million
because, as a result mainly of the increased level of capital
expenditures resulting from the September 2003 equity offering,
we believed we would have reversals of existing temporary
differences between book and taxable income sufficient to result
in future net deferred tax liabilities. The $1.8 million
net deferred tax asset consisted of a $1.2 million deferred
income tax benefit and a $0.6 million tax effect of
unrealized hedging losses.
In 2004, we recognized a current year net deferred tax liability
of $10.6 million due to reversals of our existing temporary
differences between book and taxable income resulting mainly
from our capital expenditures. The $10.6 million net deferred
tax liability consisted of a $10.9 million deferred income
tax expense, a $0.3 million tax effect of unrealized
hedging gains, and a $0.6 million credit to equity for the tax
benefit from the exercise of stock options. At December 31,
2004, we believe it is more likely than not that capital loss
carryforwards of approximately $1.8 million may expire
unused and, accordingly, have 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
preferred stock and were required to pay dividends on our
Series B preferred stock. At our option, these dividends
may and were able to 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 2004, 2003
and 2002.
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.”
48
The following table shows the effect on our balance sheet for
the years ended December 31, 2004, 2003 and 2002 of the
issuance of additional shares of preferred stock in lieu of
paying cash dividends.
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, | |
| |
|
| |
| |
|
|
|
% | |
|
|
|
% | |
|
|
| |
|
2004 | |
|
Change | |
|
2003 | |
|
Change | |
|
2002 | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
| |
|
(In thousands, except for shares issued) | |
|
Dividends
|
|
$ |
726 |
|
|
|
(76 |
%) |
|
$ |
3,061 |
|
|
|
13 |
% |
|
$ |
2,713 |
|
|
Accretion of mandatorily redeemable preferred stock
|
|
|
— |
|
|
|
(100 |
%) |
|
|
387 |
|
|
|
62 |
% |
|
|
239 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
$ |
726 |
|
|
|
(79 |
%) |
|
$ |
3,448 |
|
|
|
17 |
% |
|
$ |
2,952 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional preferred shares issued
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Series A
|
|
|
36,264 |
|
|
|
(73 |
%) |
|
|
132,490 |
|
|
|
(1 |
%) |
|
|
134,440 |
|
|
Series B
|
|
|
— |
|
|
|
(100 |
%) |
|
|
30,603 |
|
|
|
2,396 |
% |
|
|
1,226 |
|
Analysis of Changes In Cash and Cash Equivalents
The table below summarizes our sources and uses of cash during
2004, 2003 and 2002.
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, | |
| |
|
| |
| |
|
|
|
% | |
|
|
|
% | |
|
|
| |
|
2004 | |
|
Change | |
|
2003 | |
|
Change | |
|
2002 | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
| |
|
(In thousands) | |
|
Net income, as restated
|
|
$ |
19,650 |
|
|
|
9 |
% |
|
$ |
18,030 |
|
|
|
NM |
|
|
$ |
2,276 |
|
|
Non-cash charges
|
|
|
36,455 |
|
|
|
88 |
% |
|
|
19,357 |
|
|
|
9 |
% |
|
|
17,734 |
|
|
Changes in working capital and other items
|
|
|
276 |
|
|
|
(94 |
%) |
|
|
4,304 |
|
|
|
(52 |
%) |
|
|
8,963 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows provided by operating activities
|
|
$ |
56,381 |
|
|
|
35 |
% |
|
$ |
41,691 |
|
|
|
44 |
% |
|
$ |
28,973 |
|
|
Cash flows used by investing activities
|
|
|
(84,645 |
) |
|
|
84 |
% |
|
|
(46,089 |
) |
|
|
69 |
% |
|
|
(27,206 |
) |
|
Cash flows provided (used) by financing activities
|
|
|
24,766 |
|
|
|
NM |
|
|
|
(5,141 |
) |
|
|
NM |
|
|
|
8,439 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
$ |
(3,498 |
) |
|
|
(63 |
%) |
|
$ |
(9,539 |
) |
|
|
NM |
|
|
$ |
10,206 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Analysis of net cash provided by operating
activities |
For 2004 compared to 2003, net cash provided by operating
activities increased by $14.7 million. The following were
the primary reasons for this change.
|
|
|
| |
• |
Net cash provided by operating activities increased by
$20.2 million due to an increase in our production volumes
combined with an increase in the prices that we received for oil
and natural gas and a decrease in losses on the settlement of
our derivative contracts. |
| |
| |
• |
Higher production cost and general and administrative expenses
partially offset $2.5 million of this increase. |
| |
| |
• |
The repayment of accounts payable in excess of collections of
accounts receivable reduced net cash provided by operating
activities by $9.3 million. |
| |
| |
• |
The settlement of the gas imbalance with our industry
participant in our Diablo project increased net cash provided by
operating activities by $2.8 million. |
| |
| |
• |
An increase in advances paid to us by participants in our 3-D
seismic projects and certain wells increased net cash provided
by operating activities by $3.2 million. |
49
For 2003 compared to 2002, net cash provided by operating
activities increased by $12.7 million. The following were
the primary reason for this change.
|
|
|
| |
• |
An increase in the sales price that we received for the sale of
our oil and natural gas during 2003 and an increase in 2003
production volumes led to an increase in net cash provided by
operating activities of $18.9 million and
$2.3 million, respectively. These increases were partially
offset by a $4.8 million increase in losses related to the
settlement of hedging contracts during 2003. |
| |
| |
• |
An increase in production cost and cash general and
administrative expenses during 2003 reduced net cash provided by
operating activities by $2.1 million. |
| |
| |
• |
A decrease in cash interest expense combined with a decrease in
interest income and other income resulted in a $2.9 million
increase to net cash provided by operating activities. |
| |
| |
• |
The collections of accounts receivable in excess of the payment
of accounts payable resulted in an increase to net cash provided
by operating activities of $1.4 million. |
| |
| |
• |
The partial settlement of our gas imbalance related to the wells
in Home Run Triple Crown and Floyd Fault Block Fields resulted
in a decrease to net cash provided by operating activities of
$3.2 million. 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. |
| |
| |
• |
An increase in the amount of royalties that we paid to royalty
owners in 2003 resulted in a $3.6 million decrease to net
cash provided by operating activities. |
| |
| |
• |
A decrease in advances paid to us by participants in our 3-D
seismic projects and certain wells combined with the elimination
of cash deposits resulted in $1.2 million increase to net
cash provided by operating activities. |
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 working capital deficit at December 31, 2004 was
$19.5 million compared to a working capital deficit of
$14.7 at December 31, 2003. This deficit included a
liability of $870,000 and an asset of $142,000 related to the
fair value our derivative contracts.
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. The deficit included a
liability of $2.1 million related to the fair value of
derivative contracts.
50
|
|
| |
Analysis of changes in cash flows used in investing
activities |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, | |
| |
|
| |
| |
|
2004 | |
|
2003 | |
|
2002(c) | |
| |
|
| |
|
| |
|
| |
| |
|
(In thousands) | |
|
Cost Incurred:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration(a)
|
|
$ |
30,189 |
|
|
$ |
20,126 |
|
|
$ |
12,693 |
|
|
Property acquisition(b)
|
|
|
6,226 |
|
|
|
4,850 |
|
|
|
2,510 |
|
|
Development(c)
|
|
|
50,497 |
|
|
|
22,285 |
|
|
|
13,301 |
|
|
Asset retirement obligation
|
|
|
513 |
|
|
|
269 |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
| |
Costs incurred
|
|
$ |
87,425 |
|
|
$ |
47,530 |
|
|
$ |
28,504 |
|
| |
|
|
|
|
|
|
|
|
|
|
Amount spent to develop proved undeveloped reserves
|
|
$ |
34,723 |
|
|
$ |
11,399 |
|
|
$ |
9,983 |
|
| |
|
|
|
|
|
|
|
|
|
(a) Includes capital expenditures for the following
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling
|
|
$ |
18,339 |
|
|
$ |
13,586 |
|
|
$ |
7,292 |
|
|
Land and seismic
|
|
|
7,991 |
|
|
|
2,470 |
|
|
|
1,685 |
|
|
Capitalized cost
|
|
|
3,859 |
|
|
|
4,070 |
|
|
|
3,716 |
|
| |
|
|
|
|
|
|
|
|
|
| |
|
$ |
30,189 |
|
|
$ |
20,126 |
|
|
$ |
12,693 |
|
| |
|
|
|
|
|
|
|
|
|
(b) Includes capital expenditures for the following
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Land and seismic
|
|
$ |
5,002 |
|
|
$ |
3,604 |
|
|
$ |
1,363 |
|
|
Capitalized cost
|
|
|
1,224 |
|
|
|
1,246 |
|
|
|
1,147 |
|
| |
|
|
|
|
|
|
|
|
|
| |
|
$ |
6,226 |
|
|
$ |
4,850 |
|
|
$ |
2,510 |
|
| |
|
|
|
|
|
|
|
|
|
(c) Includes capital expenditures for the following
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling
|
|
$ |
49,866 |
|
|
$ |
21,520 |
|
|
$ |
12,508 |
|
|
Capitalized cost
|
|
|
631 |
|
|
|
765 |
|
|
|
793 |
|
| |
|
|
|
|
|
|
|
|
|
| |
|
$ |
50,497 |
|
|
$ |
22,285 |
|
|
$ |
13,301 |
|
| |
|
|
|
|
|
|
|
|
|
For 2004 compared to 2003, net cash used by investing activities
increased 84% due to the increase in the amount of capital we
spent on drilling, land and seismic activities.
For 2003 compared to 2002, net cash used by investing activities
increased 69% due to the increase in the amount of capital we
spent on drilling, land and seismic activities.
|
|
| |
Analysis of changes in cash flows from financing
activities |
Over the three year period ended December 31, 2004, 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.
During 2004 we borrowed $33 million under our senior credit
facility. We used net proceeds from our sale of common stock in
July 2004 combined and cash on hand to repay $31 million in
borrowings.
In 2003, we reduced the amount of outstanding borrowings under
our senior credit facility by $41 million. The net proceeds
from our 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
51
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 2003, reduced the outstanding balance under our senior
subordinated notes by approximately $3 million. In 2002, we
borrowed an additional $4 million in senior subordinated
notes. We paid $86,000 in fees related to the amendment of our
senior subordinated credit agreement in December 2003.
|
|
| |
Common Stock Transactions |
| |
|
|
|
|
|
|
|
|
| |
|
Shares Issued | |
|
Net Proceeds | |
| |
|
| |
|
| |
| |
|
|
|
(In thousands) | |
|
2004 common stock transactions:
|
|
|
|
|
|
|
|
|
|
Sale of common stock under universal shelf registration
statement(a)
|
|
|
2,598,500 |
|
|
$ |
22,105 |
|
|
Exercise of employee stock options
|
|
|
314,181 |
|
|
|
972 |
|
| |
|
2003 common stock transactions:
|
|
|
|
|
|
|
|
|
|
Sale of common stock(b)
|
|
|
7,384,090 |
|
|
$ |
40,000 |
|
|
Exercise of employee stock options
|
|
|
309,760 |
|
|
|
829 |
|
| |
|
2002 common stock transactions:
|
|
|
|
|
|
|
|
|
|
Unregistered shares issued pursuant to warrant exercise(c)
|
|
|
243,902 |
|
|
$ |
625 |
|
|
Exercise of employee stock options
|
|
|
132,507 |
|
|
|
296 |
|
|
|
| (a) |
The net proceeds from the sale were used to repay outstanding
indebtedness under our senior credit facility. 2,300,000 shares
were sold in July 2004 and 298,500 shares were sold in August
2004 when the underwriter exercised its over-allotment option. |
| |
| (b) |
The net proceeds from the sale were used to accelerate the
amount of capital that we spent on our exploration and
development program and reduce our outstanding indebtedness. |
| |
| (c) |
In December 2002, we issued 243,902 unregistered shares of our
common stock to a group of institutional investors. This group
of investors was led by affiliates of two members of our then
current Board of Directors. At the time the warrants were
exercised, one of these two board members was no longer a member
of our board. For more information on the warrant exercise and
the issuance of common stock, please see “Item 5.
Market for Registrant’s Common Equity and Related
Stockholder Matters and Issuer Purchases of Equity
Securities — Recent Issuance of Unregistered
Securities.” |
For additional shares issued where we did not receive proceeds,
see “Item 5. Market for Registrant’s Common
Equity and Related Stockholder Matters and Issuer Purchases of
Equity Securities — Recent Issuance of Unregistered
Securities.”
52
|
|
| |
Mandatorily Redeemable Preferred Stock |
In 2003, we redeemed $704,000 of our Series B mandatorily
redeemable preferred stock that remained outstanding after the
CSFB conversion of the majority of the Series B preferred
stock.
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.
Other Matters
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
derivative contracts 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 derivative contracts 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.”
|
|
| |
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
You should carefully consider the following risk factors, in
addition to the other information set forth in this report. Each
of these risk factors could adversely affect our business,
operating results and financial condition.
53
|
|
| |
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.
|
|
| |
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
54
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 Derivative Contracts 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 derivative contracts that generally
result in a fixed price or a range of minimum and maximum price
limits over a specified time period. Derivative contracts limit
the benefits we would otherwise realize if actual prices rise
above the contract price.
Our derivative contracts expose us to the risk of financial loss
in certain circumstances. For example, if we do not produce our
oil and natural gas reserves at rates equivalent to our
derivative position, we would be required to satisfy our
obligations under those derivative contracts on potentially
unfavorable terms without the ability to offset 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 $1.0 million.
Additionally, because the terms of our derivative 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 prices we receive pursuant to our derivative
contracts 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 derivative
contracts prove unable or unwilling to perform their obligations
under such contracts. Additionally, in the past, some of our
derivative 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.
55
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 |
| |
| |
• |
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.
56
|
|
| |
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,
results of operations and cash flows. 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 That 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.
57
|
|
| |
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
58
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:
|
|
|
| |
• |
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 That 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
EPA, 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 CERCLA, RCRA, 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
59
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.
|
|
| |
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
March 10, 2005, one of our stockholders, together
with its affiliates, owned 13,634,882 shares of our common
stock. While none of these shares have been registered under the
Securities Act, this stockholder has certain registration
rights, that when exercised, could facilitate a sale of all or a
portion of its shares.
|
|
| |
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; |
60
|
|
|
| |
• |
the prices of oil and natural gas; |
| |
| |
• |
announcements by us and our competitors; |
| |
| |
• |
our liquidity; |
| |
| |
• |
our ability to raise additional funds; and |
| |
| |
• |
other events. |
61
Forward-Looking Statements
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 prospectus,
which describe factors that could cause our actual results to
differ from those set forth in the forward-looking statements.
62
|
|
| 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, 2004. During 2004, we were party to natural
gas swap contracts, natural gas three-way costless collars, 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 2004.
| |
|
|
|
|
|
| |
|
Fair Value of |
| |
|
Derivative |
| |
|
Contracts |
| |
|
|
| |
|
(In thousands) |
|
Estimated fair value of open contracts at December 31, 2003
|
|
$ |
(2,177 |
) |
|
Changes in fair values of contracts:
|
|
|
|
|
| |
Fixed price natural gas swaps
|
|
$ |
(294 |
) |
| |
Natural gas collars
|
|
|
(460 |
) |
| |
Fixed price oil swaps
|
|
|
(618 |
) |
| |
Oil collars
|
|
|
(1,948 |
) |
| |
Interest rate swap
|
|
|
111 |
|
|
Contract settlements:
|
|
|
|
|
| |
Fixed price natural gas swaps
|
|
$ |
1,066 |
|
| |
Natural gas collars
|
|
|
787 |
|
| |
Fixed price oil swaps
|
|
|
1,073 |
|
| |
Oil collars
|
|
|
1,768 |
|
| |
Interest rate swap
|
|
|
— |
|
| |
|
|
|
|
|
Estimated fair value of open contracts at December 31, 2004
|
|
$ |
(692 |
) |
| |
|
|
|
|
Based upon the market prices at December 31, 2004, we
expect to transfer approximately $728,000 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.
Derivative Instruments and Hedging Activities
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 derivative contracts 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 derivative contracts will vary from time to time.
63
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.
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.
Our derivative contracts accounted for as cash flow hedges
consisted of fixed-price swaps, costless collars (purchased put
options and written call options) and the costless collar
portion of a three-way costless collar (purchased put option
options and written call options).
Our fixed-price swap agreements are used to fix the sales price
for our anticipated future oil and natural gas production. Upon
settlement, we receive a fixed price for the hedged commodity
and pay our counterparty a floating market price, as defined in
each instrument. These instruments are settled monthly. When the
floating price exceeds the fixed price for a contract month, we
pay our counterparty. When the fixed price exceeds the floating
price, our 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.
We use costless collars to establish floor (purchased put
option) and ceiling price (written call option) on our
anticipated future oil and natural gas production. We received
no net premiums when we entered into these option agreements.
These instruments are settled monthly. When the settlement price
for a period is above the ceiling price (written call option),
we pay our counterparty. When the settlement price for a period
is below the floor price (purchased put option), our
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.
A three-way collar contract consists of a costless collar
(purchased put option and written call option) plus a put
(written put) sold by us with a price below the floor price
(purchased put option) of the costless collar. We received no
net premiums when we entered into these option agreements. These
instruments are settled monthly. The written put requires us to
make a payment to our counterparty if the settlement price for a
period is below the written put price. Combining the costless
collar (purchased put option and written call option) with the
written put results in us being entitled to a net payment equal
to the difference between the floor price (purchased put option)
of the costless collar and the written put price if the
settlement price is equal to or less than the written put price.
If the settlement price is greater than the written put price,
the result is the same as it would have been with a costless
collar. This strategy enables us to increase the floor and the
ceiling price of the collar beyond the range of a traditional
costless collar while offsetting the associated cost with the
sale of the written put. The put that we sell is not designated
as a cash flow hedge.
|
|
| |
Derivatives Not Designated as Hedges |
Our derivative positions included written put options that are
not designated as hedges and are reflected at fair value on the
balance sheet. These positions were entered into in conjunction
with a costless collar to offset the cost of other option
positions that are designated as hedges.
64
The following table reflects our open commodity derivative
contracts at March 31, 2005, the associated volumes and the
corresponding weighted average NYMEX reference price.
| |
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|
Notional Amount |
|
|
| |
|
|
|
|
|
|
|
Nymex |
| |
|
Derivative |
|
|
|
Gas |
|
Oil |
|
Reference |
| Settlement Period |
|
Instrument |
|
Hedge Strategy |
|
(MMBTU) |
|
(Barrels) |
|
Price |
| |
|
|
|
|
|
|
|
|
|
|
|
Costless Collars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
01/01/05 - 03/31/05
|
|
|
Purchased put |
|
|
|
Cash flow |
|
|
|
90,000 |
|
|
|
|
|
|
$ |
4.00 |
|
| |
|
|
|
Written call |
|
|
|
Cash flow |
|
|
|
90,000 |
|
|
|
|
|
|
|
7.25 |
|
| |
01/01/05 - 03/31/05
|
|
|
Purchased put |
|
|
|
Cash flow |
|
|
|
67,500 |
|
|
|
|
|
|
$ |
4.25 |
|
| |
|
|
|
Written call |
|
|
|
Cash flow |
|
|
|
67,500 |
|
|
|
|
|
|
|
5.90 |
|
| |
01/01/05 - 03/31/05
|
|
|
Purchased put |
|
|
|
Cash flow |
|
|
|
45,000 |
|
|
|
|
|
|
$ |
4.25 |
|
| |
|
|
|
Written call |
|
|
|
Cash flow |
|
|
|
45,000 |
|
|
|
|
|
|
|
6.50 |
|
| |
01/01/05 - 03/31/05
|
|
|
Purchased put |
|
|
|
Cash flow |
|
|
|
|
|
|
|
9,000 |
|
|
$ |
23.00 |
|
| |
|
|
|
Written call |
|
|
|
Cash flow |
|
|
|
|
|
|
|
9,000 |
|
|
|
25.07 |
|
| |
01/01/05 - 03/31/05
|
|
|
Purchased put |
|
|
|
Cash flow |
|
|
|
|
|
|
|
23,000 |
|
|
$ |
23.00 |
|
| |
|
|
|
Written call |
|
|
|
Cash flow |
|
|
|
|
|
|
|
23,000 |
|
|
|
26.90 |
|
| |
01/01/05 - 06/30/05
|
|
|
Purchased put |
|
|
|
Cash flow |
|
|
|
633,500 |
|
|
|
|
|
|
$ |
5.00 |
|
| |
|
|
|
Written call |
|
|
|
Cash flow |
|
|
|
633.500 |
|
|
|
|
|
|
|
7.40 |
|
| |
01/01/05 - 06/30/05
|
|
|
Purchased put |
|
|
|
Cash flow |
|
|
|
|
|
|
|
29,000 |
|
|
$ |
29.00 |
|
| |
|
|
|
Written call |
|
|
|
Cash flow |
|
|
|
|
|
|
|
29,000 |
|
|
|
36.00 |
|
| |
01/01/05 - 06/30/05
|
|
|
Purchased put |
|
|
|
Cash flow |
|
|
|
|
|
|
|
23,530 |
|
|
$ |
29.00 |
|
| |
|
|
|
Written call |
|
|
|
Cash flow |
|
|
|
|
|
|
|
23,530 |
|
|
|
36.00 |
|
| |
04/01/05 - 06/30/05
|
|
|
Purchased put |
|
|
|
Cash flow |
|
|
|
91,000 |
|
|
|
|
|
|
$ |
4.00 |
|
| |
|
|
|
Written call |
|
|
|
Cash flow |
|
|
|
91,000 |
|
|
|
|
|
|
|
5.40 |
|
| |
04/01/05 - 06/30/05
|
|
|
Purchased put |
|
|
|
Cash flow |
|
|
|
45,500 |
|
|
|
|
|
|
$ |
4.25 |
|
| |
|
|
|
Written call |
|
|
|
Cash flow |
|
|
|
45,500 |
|
|
|
|
|
|
|
4.52 |
|
| |
04/01/05 - 06/30/05
|
|
|
Purchased put |
|
|
|
Cash flow |
|
|
|
|
|
|
|
6,825 |
|
|
$ |
23.00 |
|
| |
|
|
|
Written call |
|
|
|
Cash flow |
|
|
|
|
|
|
|
6,825 |
|
|
|
26.45 |
|
| |
04/01/05 - 10/31/05
|
|
|
Purchased put |
|
|
|
Cash flow |
|
|
|
420,000 |
|
|
|
|
|
|
$ |
5.45 |
|
| |
|
|
|
Written call |
|
|
|
Cash flow |
|
|
|
420,000 |
|
|
|
|
|
|
|
8.00 |
|
|
Three Way Costless Collars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
01/01/05 - 3/31/05
|
|
|
Purchased put |
|
|
|
Cash flow |
|
|
|
210,000 |
|
|
|
|
|
|
$ |
6.40 |
|
| |
|
|
|
Written call |
|
|
|
Cash flow |
|
|
|
210,000 |
|
|
|
|
|
|
|
7.64 |
|
| |
|
|
|
Written put |
|
|
|
Undesignated |
|
|
|
210,000 |
|
|
|
|
|
|
|
5.50 |
|
| |
07/01/05 - 10/31/05
|
|
|
Purchased put |
|
|
|
Cash flow |
|
|
|
400,000 |
|
|
|
|
|
|
$ |
6.00 |
|
| |
|
|
|
Written call |
|
|
|
Cash flow |
|
|
|
400,000 |
|
|
|
|
|
|
|
7.20 |
|
| |
|
|
|
Written put |
|
|
|
Undesignated |
|
|
|
400,000 |
|
|
|
|
|
|
|
5.00 |
|
| |
07/01/05 - 12/31/05
|
|
|
Purchased put |
|
|
|
Cash flow |
|
|
|
|
|
|
|
30,000 |
|
|
$ |
40.00 |
|
| |
|
|
|
Written call |
|
|
|
Cash flow |
|
|
|
|
|
|
|
30,000 |
|
|
|
53.00 |
|
| |
|
|
|
Written put |
|
|
|
Undesignated |
|
|
|
|
|
|
|
30,000 |
|
|
|
30.00 |
|
| |
07/01/05 - 10/31/05
|
|
|
Purchased put |
|
|
|
Cash flow |
|
|
|
250,000 |
|
|
|
|
|
|
$ |
6.75 |
|
| |
|
|
|
Written call |
|
|
|
Cash flow |
|
|
|
250,000 |
|
|
|
|
|
|
|
8.80 |
|
| |
|
|
|
Written put |
|
|
|
Undesignated |
|
|
|
250,000 |
|
|
|
|
|
|
|
5.50 |
|
Interest Rate Risk
At December 31, 2004, we had $50.5 million in
outstanding debt, of which $29.5 million was fixed rate
debt. Our fixed rate debt consists of $20 million in senior
subordinated notes and $9.5 million in mandatorily
redeemable Series A preferred stock.
65
The estimated fair value of our senior subordinated notes at
December 31, 2004, was $20 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 October 31, 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 $21 million in outstanding debt at
December 31, 2004, 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 0.25% to 1% depending on
facility usage or (ii) Eurodollars (LIBOR) for one,
two, three or six months plus a margin which fluctuates from
1.25% to 2% depending on facility usage. The weighted average
interest rate on these borrowings at December 31, 2004, was
4.16%. A 10% increase in short-term interest rates on our
floating-rate debt outstanding at December 31, 2004 would
equal approximately 24 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 facility remained at $21 million.
Using the interest rate margins from our senior credit agreement
that was amended and restated on January 21, 2005 and the Euro
dollar rate that was in affect on our outstanding borrowings at
December 31, 2004, a 10% increase in short-term interest
would equal approximately 24 basis points. Given the margin to
the Eurodollar rate that we pay pursuant to our amended and
restated senior credit agreement, the impact to the interest
expense that we pay on borrowings would be a decrease of
$28,000. 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.
|
|
| 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
We maintain disclosure controls and procedures as defined in
Rule 13a-15(e) under the Securities Exchange Act of 1934.
Under the supervision and with the participation of our
management, including our principal executive officer and
principal financial officer, we conducted an evaluation of the
effectiveness of our disclosure controls and procedures as of
the end of the period covered by this report. This evaluation
included consideration of various accounting and financial
reporting processes in an effort to ensure that information
required to be disclosed in our Securities Exchange Act reports
is recorded, processed, summarized and reported within the time
periods specified by the SEC. This evaluation also considered
work related to our internal control over financial reporting.
Based upon this evaluation, our chief executive officer and
chief financial officer concluded that, as of December 31,
2004, as a result of the material weakness discussed below, our
disclosure controls and procedures were not effective to ensure
that the information required to be disclosed in our Securities
Exchange Act reports is recorded, processed, summarized and
reported within the requisite time periods. This not
withstanding, management believes that the financial statements
included in this report fairly present in all material respects
our financial condition, results of operations and cash flows
for the periods presented.
66
Management’s Report on Internal Control over Financial
Reporting
Management is responsible for establishing and maintaining
adequate internal control over financial reporting as defined in
Rule 13a-15(f) under the Securities Exchange Act of 1934.
Our internal control over financial reporting is a process
designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. Because of its
inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Also, projections of
any evaluation of effectiveness to future periods are subject to
the risk that controls may become inadequate because of changes
in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
Under the supervision and with the participation of our
management, including our chief executive officer and chief
financial officer, we conducted an evaluation of the design and
operating effectiveness of our internal control over financial
reporting as of December 31, 2004 based on the criteria
described in Internal Control — Integrated
Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO).
A material weakness is a control deficiency, or combination of
control deficiencies, that results in more than a remote
likelihood that a material misstatement of the annual or interim
financial statements will not be prevented or detected. As of
December 31, 2004, we did not maintain effective controls
over the accounting for depletion expense and accumulated
depletion pertaining to our proved oil and natural gas
properties in accordance with accounting principles generally
accepted in the United States of America. Specifically, our
controls related to the preparation and review of the quarterly
depletion computations were not adequate to ensure that the
changes in depletion rate estimates used to determine depletion
expense and the related accumulated depletion that are part of
net proved oil and natural gas properties are only applied
prospectively rather than to year-to-date production.
This control deficiency resulted in the restatement of our 2003
and 2002 annual consolidated financial statements and 2004 and
2003 interim consolidated financial statements as well as an
audit adjustment to the fourth quarter 2004 financial statements
to reduce the depletion expense and the related accumulated
depletion of net proved oil and natural gas property balances.
Further, in the absence of appropriate remediation this control
deficiency could result in a misstatement of depletion expense
and the related accumulated depletion of net proved oil and
natural gas property balances that would result in a material
misstatement to the annual or interim consolidated financial
statements that would not be prevented or detected. Therefore,
we have concluded that this control deficiency constitutes a
material weakness.
Because of the material weakness described above, management has
concluded that, as of December 31, 2004, we did not
maintain effective internal control over financial reporting,
based on the criteria in Internal Control —
Integrated Framework issued by the COSO.
Our management’s assessment of the effectiveness of our
internal control over financial reporting as of
December 31, 2004 has been audited by
PricewaterhouseCoopers LLP, an independent registered public
accounting firm, as stated in their report which is included
herein beginning on page F-2.
Changes in Internal Control over Financial Reporting
There was no change in our internal control over financial
reporting (as defined in Rule 13a-15(f) of the Securities
and Exchange Act of 1934) that occurred during our most recently
completed fiscal quarter that has materially affected, or is
reasonably likely to materially affect, the design or operating
effectiveness of our internal control over financial reporting.
However, since year end, we have taken action to remediate the
material weakness identified at December 31, 2004. Due to
such remediation, our depletion rate at each respective period
end will be applied to the respective current period production
only, as required by accounting principles generally accepted in
the United States of America.
67
|
|
| Item 9B. |
Other Information |
On December 20, 2004, we entered into an amendment to our
lease for the office space for our principal executive offices.
The amendment extends the term of our lease by an additional
five years and provides us with an improvement allowance, the
right to extend the term for an additional five years and a
right of first refusal with respect to additional space and the
right to terminate the lease early for a termination fee. We
inadvertently failed to make the timely disclosure on
Form 8-K and are providing it herein.
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 2005 Proxy Statement for our
annual meeting of stockholders to be held on Wednesday,
June 3, 2008. The 2005 Proxy Statement will be filed with
the Securities and Exchange Commission not later than
120 days subsequent to December 31, 2004.
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 2005 Proxy Statement, which will be filed with
the Securities and Exchange Commission not later than
120 days subsequent to December 31, 2004.
|
|
| Item 12. |
Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters |
The information required by this item is incorporated herein by
reference to the 2005 Proxy Statement, which will be filed with
the Securities and Exchange Commission not later than
120 days subsequent to December 31, 2004. See
“Item 5. Market for Registrants Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity
Securities,” which sets forth certain information with
respect to our equity compensation plans.
|
|
| Item 13. |
Certain Relationships and Related Transactions |
The information required by this item is incorporated herein by
reference to the 2005 Proxy Statement, which will be filed with
the Securities and Exchange Commission not later than
120 days subsequent to December 31, 2004.
|
|
| Item 14. |
Principal Accounting Fees and Services |
The information required by this item is incorporated herein by
reference to the 2005 Proxy Statement, which will be filed with
the Securities and Exchange Commission not later than
120 days subsequent to December 31, 2004.
68
PART IV
|
|
| Item 15. |
Exhibits, Financial Statement Schedules |
(a)1. Consolidated Financial Statements: See Index to
Financial Statements on page F-1.
2. No schedules are required
The exhibits listed in the accompanying Index to Exhibits are
filed or incorporated by reference as part of the annual report.
69
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.
70
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.
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.
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.
71
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.
72
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused
this report to be signed on its behalf by the undersigned,
hereunder duly authorized, as of March 31, 2005.
|
|
| |
Brigham Exploration Company
|
|
|
| |
|
| |
Ben M. Brigham |
| |
Chief 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 31, 2005.
| |
|
|
|
|
| |
/s/ Ben M. Brigham
Ben
M. Brigham |
|
Chief 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. Brigham |
|
Executive Vice President — Land and
Administration and Director |
| |
/s/ Harold D. Carter
Harold
D. Carter |
|
Director |
| |
/s/ Stephen C. Hurley
Stephen
C. Hurley |
|
Director |
| |
/s/ Stephen P. Reynolds
Stephen
P. Reynolds |
|
Director |
| |
/s/ Hobart A. Smith
Hobart
A. Smith |
|
Director |
| |
/s/ Steven A. Webster
Steven
A. Webster |
|
Director |
| |
/s/ R. Graham Whaling
R.
Graham Whaling |
|
Director |
73
BRIGHAM EXPLORATION COMPANY
INDEX TO FINANCIAL STATEMENTS
| |
|
|
|
|
| |
|
Page | |
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Report of Independent Registered Public Accounting Firm
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F-2 |
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Consolidated Balance Sheets as of December 31, 2004 and 2003
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F-4 |
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|
Consolidated Statements of Operations for the Years Ended
December 31, 2004, 2003 and 2002
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|
F-5 |
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|
Consolidated Statements of Stockholders’ Equity for the
Years Ended December 31, 2004, 2003 and 2002
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F-6 |
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Consolidated Statements of Cash Flows for the Years Ended
December 31, 2004, 2003 and 2002
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F-7 |
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Notes to the Consolidated Financial Statements
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F-8 |
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|
Supplemental Oil and Gas Information (Unaudited)
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F-36 |
|
|
Supplemental Quarterly Financial Information (Unaudited)
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F-39 |
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F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Brigham
Exploration Company:
We have completed an integrated audit of Brigham Exploration
Company’s 2004 consolidated financial statements and of its
internal control over financial reporting as of
December 31, 2004 and audits of its 2003 and 2002
consolidated financial statements in accordance with the
standards of the Public Company Accounting Oversight Board
(United States). Our opinions, based on our audits, are
presented below.
Consolidated financial statements
In our opinion, the consolidated financial statements listed in
the index appearing under Item 15(a)(1) present fairly, in
all material respects, the financial position of Brigham
Exploration Company and its subsidiaries (the
“Company”) at December 31, 2004 and 2003, and the
results of their operations and their cash flows for each of the
three years in the period ended December 31, 2004 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 the standards of the Public
Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit of financial statements
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.
As discussed in Note 2, the 2003 and 2002 consolidated
financial statements have been restated to revise the
computation of depletion expense related to net proved oil and
natural gas properties.
As discussed in Note 1, the Company adopted Statement of
Financial Accounting Standards (“SFAS”) No. 143,
“Accounting for Asset Retirement Obligations” on
January 1, 2003, and adopted SFAS No. 150,
“Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity” on
July 1, 2003.
Internal control over financial reporting
Also, we have audited management’s assessment, included in
Management’s Report on Internal Control over Financial
Reporting appearing under Item 9A, that the Company did not
maintain effective internal control over financial reporting as
of December 31, 2004, because the Company did not maintain
effective controls over the accounting for depletion expense and
accumulated depletion pertaining to its proved oil and natural
gas properties in accordance with generally accepted accounting
principles generally accepted in the United States of America,
based on criteria established in Internal Control —
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). The
Company’s management is responsible for maintaining
effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over
financial reporting. Our responsibility is to express opinions
on management’s assessment and on the effectiveness of the
Company’s internal control over financial reporting based
on our audit.
We conducted our audit of internal control over financial
reporting in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable
assurance about whether effective internal control over
financial reporting was maintained in all material respects. An
audit of internal control over financial reporting includes
obtaining an understanding of internal control over financial
reporting, evaluating management’s assessment, testing and
evaluating the design and operating effectiveness of internal
control,
F-2
and performing such other procedures as we consider necessary in
the circumstances. We believe that our audit provides a
reasonable basis for our opinions.
A company’s internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s
internal control over financial reporting includes those
policies and procedures that (i) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (ii) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of
financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the
company are being made only in accordance with authorizations of
management and directors of the company; and (iii) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
company’s assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
A material weakness is a control deficiency, or combination of
control deficiencies, that results in more than a remote
likelihood that a material misstatement of the annual or interim
financial statements will not be prevented or detected. The
following material weakness has been identified and included in
management’s assessment. As of December 31, 2004, the
Company did not maintain effective controls over the accounting
for depletion expense and accumulated depletion pertaining to
its proved oil and natural gas properties in accordance with
accounting principles generally accepted in the United States of
America. Specifically, the Company’s controls related to
the preparation and review of the quarterly depletion
computations were not adequate to ensure that the changes in
depletion rate estimates used to determine depletion expense and
the related accumulated depletion of net proved oil and natural
gas properties are only applied prospectively rather than to
year-to-date production.
This control deficiency resulted in the restatement of the
Company’s 2003 and 2002 annual consolidated financial
statements and 2004 and 2003 interim consolidated financial
statements as well as an audit adjustment to the fourth quarter
2004 financial statements to reduce depletion expense and the
related accumulated depletion of net proved oil and natural gas
property balances. Further, this control deficiency could result
in a misstatement of depletion expense and the related
accumulated depletion of net proved oil and natural gas property
balances that would result in a material misstatement to the
annual or interim consolidated financial statements that would
not be prevented or detected. Therefore, the Company concluded
that this control deficiency constitutes a material weakness.
This material weakness was considered in determining the nature,
timing, and extent of audit tests applied in our audit of the
2004 consolidated financial statements, and our opinion
regarding the effectiveness of the Company’s internal
control over financial reporting does not affect our opinion on
those consolidated financial statements.
In our opinion, management’s assessment that Brigham
Exploration Company did not maintain effective internal control
over financial reporting as of December 31, 2004, is fairly
stated, in all material respects, based on criteria established
in Internal Control — Integrated Framework
issued by the COSO. Also, in our opinion, because of the
effect of the material weakness described above on the
achievement of the objectives of the control criteria, Brigham
Exploration Company has not maintained effective control over
financial reporting as of December 31, 2004, based on
criteria established in Internal Control —
Integrated Framework issued by the COSO.
/s/ PricewaterhouseCoopers LLP
March 30, 2005
Houston, Texas
F-3
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
| |
|
|
|
|
|
|
|
|
|
|
| |
|
December 31, |
| |
|
|
| |
|
2004 |
|
2003 |
| |
|
|
|
|
| |
|
|
|
Restated |
| |
|
(In thousands, |
| |
|
except share data) |
|
ASSETS |
|
Current assets:
|
|
|
|
|
|
|
|
|
| |
Cash and cash equivalents
|
|
$ |
2,281 |
|
|
$ |
5,779 |
|
| |
Accounts receivable
|
|
|
17,573 |
|
|
|
11,143 |
|
| |
Deferred income taxes
|
|
|
239 |
|
|
|
307 |
|
| |
Other current assets
|
|
|
901 |
|
|
|
3,606 |
|
| |
|
|
|
|
|
|
|
|
| |
|
Total current assets
|
|
|
20,994 |
|
|
|
20,835 |
|
| |
|
|
|
|
|
|
|
|
|
Oil and natural gas properties, using the full cost method of
accounting
|
|
|
|
|
|
|
|
|
| |
Proved
|
|
|
355,834 |
|
|
|
277,351 |
|
| |
Unproved
|
|
|
47,356 |
|
|
|
38,506 |
|
| |
Accumulated depletion
|
|
|
(141,211 |
) |
|
|
(117,367 |
) |
| |
|
|
|
|
|
|
|
|
| |
|
|
261,979 |
|
|
|
198,490 |
|
| |
|
|
|
|
|
|
|
|
|
Other property and equipment, net
|
|
|
1,209 |
|
|
|
1,219 |
|
|
Deferred income taxes
|
|
|
— |
|
|
|
1,477 |
|
|
Deferred loan fees
|
|
|
1,745 |
|
|
|
2,501 |
|
|
Other noncurrent assets
|
|
|
380 |
|
|
|
460 |
|
| |
|
|
|
|
|
|
|
|
| |
|
Total assets
|
|
$ |
286,307 |
|
|
$ |
224,982 |
|
| |
|
|
|
|
|
|
|
|
| |
|
LIABILITIES AND STOCKHOLDERS’ EQUITY |
|
Current liabilities:
|
|
|
|
|
|
|
|
|
| |
Accounts payable
|
|
$ |
22,465 |
|
|
$ |
19,806 |
|
| |
Royalties payable
|
|
|
6,072 |
|
|
|
5,280 |
|
| |
Accrued drilling costs
|
|
|
6,099 |
|
|
|
3,916 |
|
| |
Participant advances received
|
|
|
3,633 |
|
|
|
1,179 |
|
| |
Other current liabilities
|
|
|
2,225 |
|
|
|
5,398 |
|
| |
|
|
|
|
|
|
|
|
| |
|
Total current liabilities
|
|
|
40,494 |
|
|
|
35,579 |
|
| |
|
|
|
|
|
|
|
|
|
Senior credit facility
|
|
|
21,000 |
|
|
|
19,000 |
|
|
Senior subordinated notes
|
|
|
20,000 |
|
|
|
20,000 |
|
|
Series A Preferred Stock, mandatorily redeemable,
$.01 par value, $20 stated and redemption value,
2,250,000 shares authorized, 475,986 and
439,722 shares issued and outstanding at December 31,
2004 and 2003, respectively
|
|
|
9,520 |
|
|
|
8,794 |
|
|
Deferred income taxes
|
|
|
9,031 |
|
|
|
— |
|
|
Other noncurrent liabilities
|
|
|
2,986 |
|
|
|
2,498 |
|
|
Commitments and contingencies (Note 10)
|
|
|
|
|
|
|
|
|
|
Stockholders’ equity:
|
|
|
|
|
|
|
|
|
| |
Common stock, $.01 par value, 50 million shares
authorized, 43,231,499 and 40,246,729 shares issued and
42,034,351 and 39,086,096 shares outstanding at
December 31, 2004 and 2003, respectively
|
|
|
432 |
|
|
|
402 |
|
| |
Additional paid-in capital
|
|
|
175,270 |
|
|
|
151,263 |
|
| |
Treasury stock, at cost; 1,197,148 and 1,160,633 shares at
December 31, 2004 and 2003, respectively
|
|
|
(4,707 |
) |
|
|
(4,402 |
) |
| |
Unearned stock compensation
|
|
|
(1,570 |
) |
|
|
(1,816 |
) |
| |
Accumulated other comprehensive income (loss)
|
|
|
(503 |
) |
|
|
(1,040 |
) |
| |
Retained earnings (accumulated deficit)
|
|
|
14,354 |
|
|
|
(5,296 |
) |
| |
|
|
|
|
|
|
|
|
| |
|
Total stockholders’ equity
|
|
|
183,276 |
|
|
|
139,111 |
|
| |
|
|
|
|
|
|
|
|
| |
|
Total liabilities and stockholders’ equity
|
|
$ |
286,307 |
|
|
$ |
224,982 |
|
| |
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-4
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, |
| |
|
|
| |
|
2004 |
|
2003 |
|
2002 |
| |
|
|
|
|
|
|
| |
|
|
|
Restated |
|
Restated |
| |
|
(In thousands, |
| |
|
except per share data) |
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Oil and natural gas sales
|
|
$ |
71,713 |
|
|
$ |
51,545 |
|
|
$ |
35,100 |
|
| |
Other revenue
|
|
|
515 |
|
|
|
132 |
|
|
|
76 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
72,228 |
|
|
|
51,677 |
|
|
|
35,176 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Lease operating
|
|
|
6,173 |
|
|
|
5,200 |
|
|
|
3,759 |
|
| |
Production taxes
|
|
|
3,107 |
|
|
|
2,477 |
|
|
|
1,977 |
|
| |
General and administrative
|
|
|
5,392 |
|
|
|
4,500 |
|
|
|
4,971 |
|
| |
Depletion of oil and natural gas properties
|
|
|
23,844 |
|
|
|
16,819 |
|
|
|
14,694 |
|
| |
Depreciation and amortization
|
|
|
722 |
|
|
|
629 |
|
|
|
440 |
|
| |
Accretion of discount on asset retirement obligations
|
|
|
159 |
|
|
|
142 |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
39,397 |
|
|
|
29,767 |
|
|
|
25,841 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Operating income
|
|
|
32,831 |
|
|
|
21,910 |
|
|
|
9,335 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Interest income
|
|
|
84 |
|
|
|
45 |
|
|
|
119 |
|
| |
Interest expense, net
|
|
|
(3,144 |
) |
|
|
(4,815 |
) |
|
|
(6,238 |
) |
| |
Debt conversion expense
|
|
|
— |
|
|
|
— |
|
|
|
(630 |
) |
| |
Other income (expense)
|
|
|
742 |
|
|
|
(601 |
) |
|
|
(310 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
(2,318 |
) |
|
|
(5,371 |
) |
|
|
(7,059 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes and cumulative effect of change in
accounting principle
|
|
|
30,513 |
|
|
|
16,539 |
|
|
|
2,276 |
|
|
Income tax benefit (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Current
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
| |
Deferred
|
|
|
(10,863 |
) |
|
|
1,223 |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
(10,863 |
) |
|
|
1,223 |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before cumulative effect of change in accounting principle
|
|
|
19,650 |
|
|
|
17,762 |
|
|
|
2,276 |
|
|
Cumulative effect of change in accounting principle, net of taxes
|
|
|
— |
|
|
|
268 |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
19,650 |
|
|
|
18,030 |
|
|
|
2,276 |
|
|
Less accretion and dividends on redeemable preferred stock
|
|
|
— |
|
|
|
3,448 |
|
|
|
2,952 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) available to common stockholders
|
|
$ |
19,650 |
|
|
$ |
14,582 |
|
|
$ |
(676 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share available to common stockholders:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Income before cumulative effect of change in accounting principle
|
|
$ |
0.49 |
|
|
$ |
0.62 |
|
|
$ |
(0.04 |
) |
| |
|
Cumulative effect of change in accounting principle
|
|
|
— |
|
|
|
0.01 |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
$ |
0.49 |
|
|
$ |
0.63 |
|
|
$ |
(0.04 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Income before cumulative effect of change in accounting principle
|
|
$ |
0.47 |
|
|
$ |
0.51 |
|
|
$ |
(0.04 |
) |
| |
|
Cumulative effect of change in accounting principle
|
|
|
— |
|
|
|
0.01 |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
$ |
0.47 |
|
|
$ |
0.52 |
|
|
$ |
(0.04 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Basic
|
|
|
40,445 |
|
|
|
23,363 |
|
|
|
16,138 |
|
| |
|
Diluted
|
|
|
41,616 |
|
|
|
34,354 |
|
|
|
16,138 |
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-5
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
Accumulated | |
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
Other | |
|
Retained | |
|
|
| |
|
Common Stock | |
|
Additional | |
|
|
|
Unearned | |
|
Comprehensive | |
|
Earnings | |
|
Total | |
| |
|
| |
|
Paid In | |
|
Treasury | |
|
Stock | |
|
Income | |
|
(Accumulated | |
|
Stockholders’ | |
| |
|
Shares | |
|
Amounts | |
|
Capital | |
|
Stock | |
|
Compensation | |
|
(Loss) | |
|
Deficit) | |
|
Equity | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
| |
|
(In thousands) | |
|
Balance, December 31, 2001 (restated)
|
|
|
17,127 |
|
|
$ |
171 |
|
|
$ |
80,466 |
|
|
$ |
(4,165 |
) |
|
$ |
(494 |
) |
|
$ |
351 |
|
|
$ |
(25,602 |
) |
|
$ |
50,727 |
|
|
Comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Net income (restated)
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
2,276 |
|
|
|
2,276 |
|
| |
Unrealized loss on cash flow hedges
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(3,519 |
) |
|
|
— |
|
|
|
(3,519 |
) |
| |
Net losses included in net income
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
121 |
|
|
|
— |
|
|
|
121 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Comprehensive income (loss) (restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,122 |
) |
|
Exercise of employee stock options
|
|
|
133 |
|
|
|
1 |
|
|
|
295 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
296 |
|
|
Expiration of employee stock options
|
|
|
— |
|
|
|
— |
|
|
|
(46 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(46 |
) |
|
Forfeitures of restricted stock
|
|
|
— |
|
|
|
— |
|
|
|
(1 |
) |
|
|
(41 |
) |
|
|
15 |
|
|
|
— |
|
|
|
— |
|
|
|
(27 |
) |
|
Revision of terms of employee stock options
|
|
|
— |
|
|
|
— |
|
|
|
596 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
596 |
|
|
Repurchases of common stock
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(76 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(76 |
) |
|
Issuance of warrants
|
|
|
— |
|
|
|
— |
|
|
|
4,605 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
4,605 |
|
|
Warrants exercised for common stock
|
|
|
244 |
|
|
|
2 |
|
|
|
623 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
625 |
|
|
Common stock issued in exchange for warrants and convertible
debt rights
|
|
|
550 |
|
|
|
6 |
|
|
|
(56 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(50 |
) |
|
Debt converted to common stock
|
|
|
2,564 |
|
|
|
26 |
|
|
|
9,906 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
9,932 |
|
|
In 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 |
|
|
|
— |
|
|
|
— |
|
|
|
267 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2002 (restated)
|
|
|
20,618 |
|
|
$ |
206 |
|
|
$ |
93,436 |
|
|
$ |
(4,282 |
) |
|
$ |
(212 |
) |
|
$ |
(3,047 |
) |
|
$ |
(23,326 |
) |
|
$ |
62,775 |
|
|
Comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Net income (restated)
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
18,030 |
|
|
|
18,030 |
|
| |
Unrealized gain on cash flow hedges
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
991 |
|
|
|
— |
|
|
|
991 |
|
| |
Tax benefits related to cash flow hedges
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
561 |
|
|
|
— |
|
|
|
561 |
|
| |
Net losses included in net income
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
455 |
|
|
|
— |
|
|
|
455 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Comprehensive income (restated)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,037 |
|
|
Issuance of common stock
|
|
|
7,384 |
|
|
|
74 |
|
|
|
39,926 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
40,000 |
|
|
Issuance of restricted stock
|
|
|
— |
|
|
|
— |
|
|
|
1,831 |
|
|
|
— |
|
|
|
(1,831 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
Issuance of stock options
|
|
|
— |
|
|
|
— |
|
|
|
296 |
|
|
|
— |
|
|
|
(296 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
Exercise of employee stock options
|
|
|
310 |
|
|
|
3 |
|
|
|
826 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
829 |
|
|
Expiration 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 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
18,534 |
|
|
In 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 |
|
|
|
— |
|
|
|
— |
|
|
|
521 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2003 (restated)
|
|
|
40,247 |
|
|
$ |
402 |
|
|
$ |
151,263 |
|
|
$ |
(4,402 |
) |
|
$ |
(1,816 |
) |
|
$ |
(1,040 |
) |
|
$ |
(5,296 |
) |
|
$ |
139,111 |
|
|
Comprehensive income (loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Net income
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
19,650 |
|
|
|
19,650 |
|
| |
Unrealized gain on cash flow hedges
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
1,485 |
|
|
|
— |
|
|
|
1,485 |
|
| |
Tax provisions related to cash flow hedges
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(290 |
) |
|
|
— |
|
|
|
(290 |
) |
| |
Net gains included in net income
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(658 |
) |
|
|
— |
|
|
|
(658 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,187 |
|
|
Issuance of common stock
|
|
|
2,598 |
|
|
|
26 |
|
|
|
22,079 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
22,105 |
|
|
Issuance of restricted stock
|
|
|
— |
|
|
|
— |
|
|
|
514 |
|
|
|
— |
|
|
|
(514 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
Vesting of restricted stock
|
|
|
72 |
|
|
|
1 |
|
|
|
(1 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
Exercise of employee stock options
|
|
|
314 |
|
|
|
3 |
|
|
|
969 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
972 |
|
|
Forfeitures of restricted stock
|
|
|
— |
|
|
|
— |
|
|
|
(131 |
) |
|
|
(4 |
) |
|
|
131 |
|
|
|
— |
|
|
|
— |
|
|
|
(4 |
) |
|
Tax benefit from the exercise of stock options
|
|
|
— |
|
|
|
— |
|
|
|
577 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
577 |
|
|
Repurchases of common stock
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(301 |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(301 |
) |
|
Amortization of unearned stock compensation
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
629 |
|
|
|
— |
|
|
|
— |
|
|
|
629 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2004
|
|
|
43,231 |
|
|
$ |
432 |
|
|
$ |
175,270 |
|
|
$ |
(4,707 |
) |
|
$ |
(1,570 |
) |
|
$ |
(503 |
) |
|
$ |
14,354 |
|
|
$ |
183,276 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-6
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, | |
| |
|
| |
| |
|
2004 | |
|
2003 | |
|
2002 | |
| |
|
| |
|
| |
|
| |
| |
|
|
|
Restated(1) | |
|
Restated(1) | |
| |
|
(In thousands) | |
|
Cash flows from operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Net income
|
|
$ |
19,650 |
|
|
$ |
18,030 |
|
|
$ |
2,276 |
|
| |
Adjustments to reconcile net income to cash provided
(used) by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Depletion of oil and natural gas properties
|
|
|
23,844 |
|
|
|
16,819 |
|
|
|
14,694 |
|
| |
|
Depreciation and amortization
|
|
|
722 |
|
|
|
629 |
|
|
|
440 |
|
| |
|
Interest paid through issuance of additional senior subordinated
notes
|
|
|
— |
|
|
|
1,196 |
|
|
|
1,076 |
|
| |
|
Interest paid through issuance of additional mandatorily
redeemable preferred stock
|
|
|
726 |
|
|
|
340 |
|
|
|
— |
|
| |
|
Amortization of deferred loan fees
|
|
|
766 |
|
|
|
1,053 |
|
|
|
1,191 |
|
| |
|
Accretion of discount on asset retirement obligations
|
|
|
159 |
|
|
|
142 |
|
|
|
— |
|
| |
|
Market value adjustment for derivative instruments
|
|
|
(625 |
) |
|
|
669 |
|
|
|
(263 |
) |
| |
|
Stock option compensation expense
|
|
|
— |
|
|
|
— |
|
|
|
596 |
|
| |
|
Deferred income taxes
|
|
|
10,863 |
|
|
|
(1,223 |
) |
|
|
— |
|
| |
|
Cumulative effect of change in accounting principle
|
|
|
— |
|
|
|
(268 |
) |
|
|
— |
|
| |
|
Changes in working capital and other items:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
Accounts receivable
|
|
|
(6,430 |
) |
|
|
218 |
|
|
|
(2,248 |
) |
| |
|
|
Other current assets
|
|
|
2,848 |
|
|
|
3,037 |
|
|
|
(4,534 |
) |
| |
|
|
Accounts and royalties payable
|
|
|
3,451 |
|
|
|
6,092 |
|
|
|
10,703 |
|
| |
|
|
Other current liabilities
|
|
|
552 |
|
|
|
(4,975 |
) |
|
|
5,060 |
|
| |
|
|
Noncurrent assets
|
|
|
— |
|
|
|
— |
|
|
|
2 |
|
| |
|
|
Noncurrent liabilities
|
|
|
(145 |
) |
|
|
(68 |
) |
|
|
(20 |
) |
| |
|
|
|
|
|
|
|
|
|
| |
|
|
|
Net cash provided by operating activities
|
|
|
56,381 |
|
|
|
41,691 |
|
|
|
28,973 |
|
| |
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Additions to oil and natural gas properties
|
|
|
(84,439 |
) |
|
|
(45,842 |
) |
|
|
(27,696 |
) |
| |
Proceeds from sale of oil and natural gas properties
|
|
|
92 |
|
|
|
427 |
|
|
|
871 |
|
| |
Additions to other property and equipment
|
|
|
(378 |
) |
|
|
(349 |
) |
|
|
(249 |
) |
| |
(Increase) decrease in drilling advances paid
|
|
|
80 |
|
|
|
(325 |
) |
|
|
(132 |
) |
| |
|
|
|
|
|
|
|
|
|
| |
|
|
|
Net cash used by investing activities
|
|
|
(84,645 |
) |
|
|
(46,089 |
) |
|
|
(27,206 |
) |
| |
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Proceeds from issuance of common stock, net of issuance costs
|
|
|
22,105 |
|
|
|
40,000 |
|
|
|
— |
|
| |
Redemption of Series B mandatorily redeemable preferred
stock
|
|
|
— |
|
|
|
(704 |
) |
|
|
— |
|
| |
Proceeds from issuance of preferred stock and warrants
|
|
|
— |
|
|
|
— |
|
|
|
9,356 |
|
| |
Proceeds from issuance of senior subordinated notes and warrants
|
|
|
— |
|
|
|
— |
|
|
|
4,000 |
|
| |
Proceeds from exercise of employee stock options
|
|
|
972 |
|
|
|
829 |
|
|
|
296 |
|
| |
Proceeds from exercise of warrants
|
|
|
— |
|
|
|
— |
|
|
|
625 |
|
| |
Fees paid due to common stock exchange for warrants
|
|
|
— |
|
|
|
— |
|
|
|
(50 |
) |
| |
Repurchases of common stock
|
|
|
(301 |
) |
|
|
(110 |
) |
|
|
(76 |
) |
| |
Increase in senior credit facility
|
|
|
33,000 |
|
|
|
6,000 |
|
|
|
— |
|
| |
Repayment of senior credit facility
|
|
|
(31,000 |
) |
|
|
(47,000 |
) |
|
|
(5,000 |
) |
| |
Principal payments on senior subordinated notes
|
|
|
— |
|
|
|
(2,993 |
) |
|
|
— |
|
| |
Principal payments on capital lease obligations
|
|
|
— |
|
|
|
— |
|
|
|
(28 |
) |
| |
Deferred loan fees paid
|
|
|
(10 |
) |
|
|
(1,163 |
) |
|
|
(684 |
) |
| |
|
|
|
|
|
|
|
|
|
| |
|
|
|
Net cash provided (used) by financing activities
|
|
|
24,766 |
|
|
|
(5,141 |
) |
|
|
8,439 |
|
| |
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents
|
|
|
(3,498 |
) |
|
|
(9,539 |
) |
|
|
10,206 |
|
|
Cash and cash equivalents, beginning of year
|
|
|
5,779 |
|
|
|
15,318 |
|
|
|
5,112 |
|
| |
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of year
|
|
$ |
2,281 |
|
|
$ |
5,779 |
|
|
$ |
15,318 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
| (1) |
Only individual line items in cash flows from operating
activities have been restated. Total cash flows from continuing
operating, investing and financing activities were unaffected. |
The accompanying notes are an integral part of these
consolidated financial statements.
F-7
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 Texas Gulf Coast, the Anadarko Basin and West Texas.
Summary of Significant Accounting Policies
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.
Brigham uses the full cost method of accounting for oil and
natural gas properties. Under this method, all acquisition,
exploration and development costs, including certain 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, asset retirement
costs under Statement of Financial Accounting Standards
No. 143, “Accounting for Asset Retirement
Obligations” (SFAS 143) 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
F-8
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
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. 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,
including exploration wells in progress at December 31, 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 years |
|
Machinery and equipment
|
|
5 years |
|
3-D seismic interpretation workstations and software
|
|
3 years |
Betterments and major improvements that extend the useful lives
are capitalized while expenditures for repairs and maintenance
of a minor nature are expensed as incurred.
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 gas imbalances were recorded as of
December 31, 2003 (dollars in thousands):
| |
|
|
|
|
|
|
|
|
| |
|
2003 | |
| |
|
| |
| |
|
Value | |
|
MMcf | |
| |
|
| |
|
| |
|
Gas imbalance receivable
|
|
$ |
2,477 |
|
|
|
451 |
|
|
Gas imbalance payable
|
|
|
2,064 |
|
|
|
505 |
|
|
|
|
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.
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
F-9
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
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.
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 11 for a
description of the derivative contracts which Brigham executes.
|
|
|
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.
The components of other comprehensive income (loss) for the
years ended December 31, 2004, 2003 and 2002 follow (in
thousands):
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
2004 | |
|
2003 | |
|
2002 | |
| |
|
| |
|
| |
|
| |
|
Balance, beginning of year
|
|
$ |
(1,040 |
) |
|
$ |
(3,047 |
) |
|
$ |
351 |
|
| |
Current period settlements reclassified to earnings
|
|
|
4,694 |
|
|
|
6,692 |
|
|
|
1,847 |
|
| |
Current period change in fair value of hedges
|
|
|
(3,209 |
) |
|
|
(5,701 |
) |
|
|
(5,366 |
) |
| |
Tax benefits related to cash flow hedges
|
|
|
(290 |
) |
|
|
561 |
|
|
|
— |
|
| |
Net (gains) losses included in earnings
|
|
|
(658 |
) |
|
|
455 |
|
|
|
121 |
|
| |
|
|
|
|
|
|
|
|
|
|
Balance, end of year
|
|
$ |
(503 |
) |
|
$ |
(1,040 |
) |
|
$ |
(3,047 |
) |
| |
|
|
|
|
|
|
|
|
|
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
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, 2004,
2003 and 2002:
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
2004 | |
|
2003 | |
|
2002 | |
| |
|
| |
|
| |
|
| |
|
Risk-free interest rate
|
|
|
3.7 |
% |
|
|
3.7 |
% |
|
|
4.1 |
% |
|
Expected life (in years)
|
|
|
3.9 |
|
|
|
5 |
|
|
|
7 |
|
|
Expected volatility
|
|
|
43 |
% |
|
|
48 |
% |
|
|
102 |
% |
|
Expected dividend yield
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
Weighted average fair value per share of stock compensation
|
|
$ |
3.31 |
|
|
$ |
2.98 |
|
|
$ |
3.44 |
|
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, 2004, 2003 and 2002 would have been the
pro forma amounts indicated below:
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, | |
| |
|
| |
| |
|
2004 | |
|
2003 | |
|
2002 | |
| |
|
| |
|
| |
|
| |
|
Net income (loss) available to common stockholders (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
As reported (restated)
|
|
$ |
19,650 |
|
|
$ |
14,582 |
|
|
$ |
(676 |
) |
| |
Add back: Stock compensation expense previously included in net
income
|
|
|
434 |
|
|
|
282 |
|
|
|
101 |
|
| |
Effect of total employee stock-based compensation expense,
determined under fair value method for all awards
|
|
|
(3,189 |
) |
|
|
(528 |
) |
|
|
(513 |
) |
| |
|
|
|
|
|
|
|
|
|
| |
Pro forma
|
|
$ |
16,895 |
|
|
$ |
14,336 |
|
|
$ |
(1,088 |
) |
| |
|
|
|
|
|
|
|
|
|
| |
Basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
As reported (restated)
|
|
$ |
0.49 |
|
|
$ |
0.63 |
|
|
$ |
(0.04 |
) |
| |
|
Pro forma
|
|
|
0.42 |
|
|
|
0.62 |
|
|
|
(0.07 |
) |
| |
Diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
As reported (restated)
|
|
$ |
0.47 |
|
|
$ |
0.52 |
|
|
$ |
(0.04 |
) |
| |
|
Pro forma
|
|
|
0.41 |
|
|
|
0.52 |
|
|
|
(0.07 |
) |
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
F-11
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
management, it is more likely than not that some portion or all
of the deferred tax assets will not be realized.
Deferred loan fees incurred in connection with the issuance of
debt are recorded on the balance sheet as deferred assets in
other noncurrent assets. 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.
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 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.
|
|
|
Asset Retirement Obligations |
In June 2001, the FASB issued Statement of Financial Accounting
Standards No. 143, “Accounting for Asset Retirement
Obligations” (SFAS 143). SFAS 143 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. 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 2004, 2003 and 2002 as if
Brigham had adopted the provisions of SFAS 143 on
January 1, 2002.
| |
|
|
|
|
|
|
|
|
|
| |
|
Year Ended | |
| |
|
December 31, | |
| |
|
| |
| |
|
2003 | |
|
2002 | |
| |
|
| |
|
| |
| |
|
(In thousands, except | |
| |
|
per share amounts) | |
| |
|
| |
|
Pro forma asset retirement obligations
|
|
$ |
2,320 |
|
|
$ |
1,931 |
|
| |
|
|
|
|
|
|
|
Net income (loss), as reported (restated)
|
|
$ |
14,582 |
|
|
$ |
(676 |
) |
|
Pro forma adjustments to reflect
|
|
|
|
|
|
|
|
|
|
retroactive adoption of SFAS 143
|
|
|
(268 |
) |
|
|
155 |
|
| |
|
|
|
|
|
|
|
Pro forma net income (loss)
|
|
$ |
14,314 |
|
|
$ |
(521 |
) |
| |
|
|
|
|
|
|
|
Net income (loss) per share:
|
|
|
|
|
|
|
|
|
| |
Basic — as reported (restated)
|
|
$ |
0.63 |
|
|
$ |
(0.04 |
) |
| |
|
|
|
|
|
|
| |
Basic — pro forma
|
|
$ |
0.61 |
|
|
$ |
(0.03 |
) |
| |
|
|
|
|
|
|
| |
Diluted — as reported (restated)
|
|
$ |
0.52 |
|
|
$ |
(0.04 |
) |
| |
|
|
|
|
|
|
| |
Diluted — pro forma
|
|
$ |
0.51 |
|
|
$ |
(0.03 |
) |
| |
|
|
|
|
|
|
F-12
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
|
|
|
Mandatorily Redeemable Preferred Stock |
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 shares remaining at December 31, 2004
and 2003 were issued to satisfy dividend requirements.
In December 2004, the Financial Accounting Standards Board
(FASB) issued SFAS No. 123R, ”Share-Based
Payment” (SFAS 123R), which is a revision of
SFAS 123 and supersedes APB Opinion No. 25.
SFAS 123R requires all share-based payments to employees,
including grants of employee stock options, to be valued at fair
value on the date of grant, and to be expensed over the
applicable vesting period. Pro forma disclosure of the income
statement effects of share-based payments is no longer an
alternative. SFAS 123R is effective for all stock-based
awards granted on or after July 1, 2005. In addition,
companies must also recognize compensation expense related to
any awards that are not fully vested as of the effective date.
Compensation expense for the unvested awards will be measured
based on the fair value of the awards previously calculated in
developing the pro forma disclosures in accordance with the
provisions of SFAS 123. Brigham is currently assessing the
impact of adopting SFAS 123R to its consolidated financial
statements.
In September 2004, the Securities and Exchange Commission
(SEC) issued Staff Accounting Bulletin 106
(SAB 106) which provides guidance regarding the interaction
of SFAS 143 with the calculation of depletion and the full
cost ceiling test of oil and gas properties under the full cost
accounting rules of the SEC. The guidance provided in
SAB 106 is not expected to have a material effect on
Brigham’s consolidated financial position, results of
operations or cash flows.
In October 2004, the American Jobs Creation Act of 2004 (AJCA)
was signed into law. In December 2004, the FASB issued Staff
Position No. 109-1 (FSP 109-1), “Application of
FASB Statement No. 109, Accounting for Income Taxes, to the
Tax Deduction on Qualified Production Activities Provided by the
American Jobs Creation Act of 2004” and Staff Position
No. 109-2 (FSP 109-2), “Accounting and Disclosure
Guidance for the Foreign Earnings Repatriation Provision within
the American Jobs Creation Act of 2004”. FSP 109-1
clarifies that the manufacturer’s tax deduction provided
for under the AJCA should be accounted for as a special
deduction in accordance with SFAS No. 109 and not as a tax
rate reduction. FSP 109-2 provides accounting and
disclosure guidance for the repatriation of certain foreign
earnings to a U.S. taxpayer as provided for in the AJCA. Brigham
does
F-13
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
not expect that the tax benefits resulting from the AJCA will
have a material impact on its financial statements.
2. Restatement
Brigham utilizes the full cost method of accounting for its
proved oil and natural gas properties included in the
consolidated financial statements. During March 2005, in
conjunction with preparation of the financial statements for the
year ended December 31, 2004, management evaluated the
manner in which Brigham historically accounted for depletion
expense associated with our oil and natural gas properties.
Historically, Brigham has calculated a depletion rate at the end
of each period within the year based on its updated reserve
estimate. This depletion rate has then been retroactively
applied to year-to-date production with the adjustment to
previously recorded depletion expense recorded in the current
quarter. Brigham has determined that the revised depletion rate
should have been applied on a prospective basis to production in
the most current quarterly period only. Therefore, management
determined it had not properly accounted for depletion expense
and related accumulated depletion that are a part of the net
proved oil and natural gas properties. As a result of this
conclusion, Brigham has restated its previously issued financial
statements for the years ended December 31, 2003 and 2002 to
reflect the revised method of computing depletion expense, and
reduced its accumulated deficit by $1,126,000 as of January 1,
2002 to reflect the impact of the revised method of depletion
expense for prior years.
The total cumulative impact of the restatement that affected
stockholders’ equity as of December 31, 2004 was an
increase in stockholders’ equity of approximately $766,000,
which includes an increase in beginning stockholders’
equity as of January 1, 2002 of approximately $1,126,000.
The overall financial increase on stockholders’ equity of
the restatement as of each year end was as follows (in
thousands):
| |
|
|
|
|
|
| |
|
Total | |
| |
|
| |
|
December 31, 2001(1)
|
|
$ |
1,126 |
|
|
December 31, 2002(2)
|
|
|
(100 |
) |
|
December 31, 2003(2)
|
|
|
(260 |
) |
| |
|
|
|
| |
Total
|
|
$ |
766 |
|
| |
|
|
|
|
|
| (1) |
The adjustment as of December 31, 2001 represents an
opening retained earnings adjustment on January 1, 2002. |
| |
| (2) |
The adjustment represents the retained earnings impact of the
restatement to net income in the respective period. |
As to the individual financial statement line items, our
historical consolidated financial statements for the years ended
December 31, 2003 and 2002, reflect the effects of the
restatement on (i) historical depletion expense and its
effects on accumulated depreciation, (ii) the impact of
income taxes and (iii) basic and diluted earnings per
share. A summary of the effects of the restatement on reported
amounts for the years ended December 31, 2003 and 2002 is
presented below. For supplemental quarterly information, see
Supplemental Quarterly Financial Information (Unaudited).
F-14
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
December 31, 2003 | |
|
December 31, 2002 | |
| |
|
| |
|
| |
| |
|
As | |
|
|
|
As | |
|
|
| |
|
Previously | |
|
|
|
Previously | |
|
|
| |
|
Reported | |
|
Adjustment | |
|
As Restated | |
|
Reported | |
|
Adjustment | |
|
As Restated | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
| |
|
(In thousands) | |
|
Consolidated Balance Sheets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Accumulated depletion
|
|
$ |
(118,546 |
) |
|
$ |
1,179 |
|
|
$ |
(117,367 |
) |
|
$ |
(102,414 |
) |
|
$ |
1,026 |
|
|
$ |
(101,388 |
) |
| |
Oil and natural gas properties, net
|
|
|
197,311 |
|
|
|
1,179 |
|
|
|
198,490 |
|
|
|
164,980 |
|
|
|
1,026 |
|
|
|
166,006 |
|
| |
Deferred income tax asset
|
|
|
1,890 |
|
|
|
(413 |
) |
|
|
1,477 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
| |
Total stockholders’ equity
|
|
|
138,345 |
|
|
|
766 |
|
|
|
139,111 |
|
|
|
61,749 |
|
|
|
1,026 |
|
|
|
62,775 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, 2003 | |
|
Year Ended December 31, 2002 | |
| |
|
| |
|
| |
| |
|
As | |
|
|
|
As | |
|
|
| |
|
Previously | |
|
|
|
As | |
|
Previously | |
|
|
|
As | |
| |
|
Reported | |
|
Adjustment | |
|
Restated | |
|
Reported | |
|
Adjustment | |
|
Restated | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
| |
|
(In thousands, except per share amounts) | |
|
Consolidated Statements of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Depletion of oil and natural gas properties
|
|
$ |
16,972 |
|
|
$ |
(153 |
) |
|
$ |
16,819 |
|
|
$ |
14,594 |
|
|
$ |
100 |
|
|
$ |
14,694 |
|
| |
Deferred income tax benefit (expense)
|
|
|
1,636 |
|
|
|
(413 |
) |
|
|
1,223 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
| |
Net income (loss) available to common stockholders
|
|
|
14,842 |
|
|
|
(260 |
) |
|
|
14,582 |
|
|
|
(576 |
) |
|
|
(100 |
) |
|
|
(676 |
) |
| |
Net income (loss) per share available to common stockholders:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Basic
|
|
$ |
0.64 |
|
|
$ |
(0.01 |
) |
|
$ |
0.63 |
|
|
$ |
(0.04 |
) |
|
$ |
— |
|
|
$ |
(0.04 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Diluted
|
|
$ |
0.53 |
|
|
$ |
(0.01 |
) |
|
$ |
0.52 |
|
|
$ |
(0.04 |
) |
|
$ |
— |
|
|
$ |
(0.04 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The restatement did not have any impact on total cash flows from
operations, investing or financing activities.
|
|
| 3. |
Property and Equipment |
Property and equipment, at cost, are summarized as follows (in
thousands):
| |
|
|
|
|
|
|
|
|
|
| |
|
December 31, | |
| |
|
| |
| |
|
2004 | |
|
2003 | |
| |
|
| |
|
| |
| |
|
|
|
(Restated) | |
|
Oil and natural gas properties
|
|
$ |
403,190 |
|
|
$ |
315,857 |
|
|
Accumulated depletion
|
|
|
(141,211 |
) |
|
|
(117,367 |
) |
| |
|
|
|
|
|
|
| |
|
|
261,979 |
|
|
|
198,490 |
|
| |
|
|
|
|
|
|
|
Other property and equipment:
|
|
|
|
|
|
|
|
|
| |
3-D seismic interpretation workstations and software
|
|
|
2,725 |
|
|
|
2,559 |
|
| |
Office furniture and equipment
|
|
|
2,784 |
|
|
|
2,572 |
|
| |
Accumulated depreciation
|
|
|
(4,300 |
) |
|
|
(3,912 |
) |
| |
|
|
|
|
|
|
| |
|
|
1,209 |
|
|
|
1,219 |
|
| |
|
|
|
|
|
|
| |
|
$ |
263,188 |
|
|
$ |
199,709 |
|
| |
|
|
|
|
|
|
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,
F-15
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
general corporate overhead, or similar activities. Capitalized
costs are summarized as follows for the years ended
December 31, 2004, 2003 and 2002 (in thousands):
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, | |
| |
|
| |
| |
|
2004 | |
|
2003 | |
|
2002 | |
| |
|
| |
|
| |
|
| |
|
Capitalized certain payroll and other internal costs
|
|
$ |
4,872 |
|
|
$ |
4,621 |
|
|
$ |
4,220 |
|
|
Capitalized interest costs
|
|
|
1,195 |
|
|
|
818 |
|
|
|
878 |
|
| |
|
|
|
|
|
|
|
|
|
| |
|
$ |
6,067 |
|
|
$ |
5,439 |
|
|
$ |
5,098 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
| 4. |
Senior Credit Facility and Senior Subordinated Notes |
| |
|
|
|
|
|
|
|
|
|
| |
|
December 31, | |
| |
|
| |
| |
|
2004 | |
|
2003 | |
| |
|
| |
|
| |
| |
|
(In thousands) | |
|
Senior Credit Facility
|
|
$ |
21,000 |
|
|
$ |
19,000 |
|
|
Senior Subordinated Notes
|
|
|
20,000 |
|
|
|
20,000 |
|
| |
|
|
|
|
|
|
|
Total Debt
|
|
$ |
41,000 |
|
|
$ |
39,000 |
|
| |
Less: Current Maturities
|
|
|
— |
|
|
|
— |
|
| |
|
|
|
|
|
|
| |
Total Long-Term Debt
|
|
$ |
41,000 |
|
|
$ |
39,000 |
|
| |
|
|
|
|
|
|
As of December 31, 2004, Brigham had $21 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, a
borrowing base of $68.5 million and matures in March 2006
which was extended to March 2009 during January 2005. 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 (2.4175%
on December 31, 2004), at Brigham’s election, plus a
margin that varies according to facility usage (1.75% on
December 31, 2004). 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. The unused portion of the committed borrowing base
is subject to an annual commitment fee of 0.5% at
December 31, 2004.
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.
In January 2005, the senior credit facility was amended and
restated to provide for revolving credit borrowings up to a
maximum of $100 million at any one time outstanding, with
borrowings not to exceed a borrowing base determined at least
semiannually. Brigham’s initial borrowing base under the
amended and restated senior credit facility is
$68.5 million. Brigham also extended the maturity date from
March 2006 to March 2009.
Borrowings under the January 2005 amended and restated senior
credit facility bear interest, at Brigham’s election, at a
base rate or LIBOR, plus in each case an applicable margin. The
applicable interest rate margin varies from 0.25% to 1.0% in the
case of borrowings based on the base rate and from
F-16
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
1.25% to 2.0% in the case of borrowings based on LIBOR,
depending on the utilization level. In addition, the unused
portion of the committed borrowing base is subject to an annual
commitment fee that varies according to facility usage. The
interest coverage ratio (as defined) under the January 2005
amended and restated senior credit facility was reduced to at
least 3 to 1. Other covenants remained unchanged from the March
2003 second amended and restated senior credit facility.
|
|
|
Senior Subordinated Notes |
As of December 31, 2004, 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 senior
credit facility that was put in place simultaneously. The terms
of the senior subordinated notes were further amended 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. Simultaneous with the completion of the
December 2003 amendment, Brigham entered into an interest rate
swap contract to exchange the floating rate coupon for a fixed
rate coupon 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 (as defined) of
at least 1.5 to 1. The terms of the senior subordinated notes
were amended again in January 2005 to further reduce the
interest rate paid on the notes, with such reduction retroactive
to October 1, 2004. Prior to the January 2005 amendment,
the senior subordinated notes bore interest at LIBOR plus a
margin of 5.05% per annum. As a consequence of the January
2005 amendment, the interest rate was reduced to LIBOR plus a
margin of 3.9%. As a consequence of the interest rate swap and
the January 2005 amendment, the senior subordinated notes paid a
7.61% fixed rate coupon per annum at December 31, 2004.
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, and 2002,
Brigham exercised this option and issued an additional $1.2 and
$1.1 million, respectively, of senior subordinated notes.
F-17
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
|
|
|
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,
2004 and 2003 (in thousands, except share amounts):
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended | |
|
Year Ended | |
| |
|
December 31, 2004 | |
|
December 31, 2003 | |
| |
|
| |
|
| |
| |
|
Shares | |
|
Amounts | |
|
Shares | |
|
Amounts | |
| |
|
| |
|
| |
|
| |
|
| |
|
Series A mandatorily redeemable preferred stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Balance, beginning of year
|
|
|
439,722 |
|
|
$ |
8,794 |
|
|
|
1,765,132 |
|
|
$ |
19,540 |
|
| |
Dividends paid in kind
|
|
|
36,264 |
|
|
|
726 |
|
|
|
132,490 |
|
|
|
2,650 |
|
| |
Accretion
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
355 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
36,264 |
|
|
|
726 |
|
|
|
132,490 |
|
|
|
3,005 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Forced 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
|
|
|
475,986 |
|
|
$ |
9,520 |
|
|
|
439,722 |
|
|
$ |
8,794 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
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-18
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 year ended December 31,
2003 (in thousands, except share amounts):
| |
|
|
|
|
|
|
|
|
|
| |
|
Year Ended | |
| |
|
December 31, 2003 | |
| |
|
| |
| |
|
Shares | |
|
Amounts | |
| |
|
| |
|
| |
|
Series B mandatorily redeemable preferred stock:
|
|
|
|
|
|
|
|
|
| |
Balance, beginning of year
|
|
|
501,226 |
|
|
$ |
4,777 |
|
| |
Dividends paid in kind
|
|
|
30,603 |
|
|
|
612 |
|
| |
Accretion
|
|
|
— |
|
|
|
32 |
|
| |
|
|
|
|
|
|
| |
|
|
30,603 |
|
|
|
644 |
|
| |
|
|
|
|
|
|
| |
Forced 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
|
|
|
— |
|
|
$ |
— |
|
| |
|
|
|
|
|
|
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 was cumulative and paid
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 could be paid by the issuance of PIK dividends for five
years. The Series B Preferred Stock would have matured in
ten years and was redeemable in whole at Brigham’s option
at 101% of the stated value five years after closing.
F-19
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
The Series B Preferred Stock ranked 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 did 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.
|
|
| 6. |
Issuance of Common Stock |
During July and August 2004, Brigham completed the sale of
2,598,500 shares of its common stock under a universal
shelf registration statement declared effective by the SEC in
June 2004. Net proceeds from the stock sale of approximately
$22.1 million were used to repay outstanding borrowings
under the senior credit facility. Brigham plans to reborrow the
repaid amounts under the senior credit facility as necessary to
fund future exploration and development activities and for
general corporate purposes.
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 5.
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 5.
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 are being used to accelerate exploration and
development activities and for general corporate purposes.
Following the offering, proceeds were used to pay down the
second amended and restated 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 February 2003, 487,805 warrants were exercised under a
cashless feature resulting in the issuance of
248,028 shares of Brigham common stock.
|
|
| 7. |
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
F-20
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
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, net of
taxes, 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 years ended December 31, 2004 and
2003 (in thousands):
| |
|
|
|
|
|
|
|
|
| |
|
Year Ended | |
|
Year Ended | |
| |
|
December 31, 2004 | |
|
December 31, 2003 | |
| |
|
| |
|
| |
|
Beginning asset retirement obligations
|
|
$ |
2,320 |
|
|
$ |
1,931 |
|
|
Liabilities incurred for new wells placed on production
|
|
|
512 |
|
|
|
269 |
|
|
Liabilities settled
|
|
|
(95 |
) |
|
|
(22 |
) |
|
Accretion of discount on asset retirement obligations
|
|
|
159 |
|
|
|
142 |
|
| |
|
|
|
|
|
|
| |
|
$ |
2,896 |
|
|
$ |
2,320 |
|
| |
|
|
|
|
|
|
8. Income Taxes
The income tax expense (benefit) consists of the following
(in thousands):
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, |
| |
|
|
| |
|
2004 | |
|
2003 | |
|
2002 |
| |
|
| |
|
| |
|
|
| |
|
|
|
Restated | |
|
|
|
Current income taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Federal
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
| |
State
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
Deferred income taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Federal
|
|
|
10,863 |
|
|
|
(1,223 |
) |
|
|
— |
|
| |
State
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
| |
|
$ |
10,863 |
|
|
$ |
(1,223 |
) |
|
$ |
— |
|
| |
|
|
|
|
|
|
|
|
|
F-21
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
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, | |
| |
|
| |
| |
|
2004 | |
|
2003 | |
|
2002 | |
| |
|
| |
|
| |
|
| |
| |
|
|
|
Restated | |
|
Restated | |
|
Tax at statutory rate
|
|
$ |
10,679 |
|
|
$ |
5,789 |
|
|
$ |
797 |
|
|
Add the effect of:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nondeductible expenses
|
|
|
5 |
|
|
|
5 |
|
|
|
223 |
|
|
Deductible stock compensation
|
|
|
(194 |
) |
|
|
(118 |
) |
|
|
(110 |
) |
|
Preferred stock dividends paid in kind
|
|
|
373 |
|
|
|
— |
|
|
|
— |
|
|
Valuation allowance
|
|
|
— |
|
|
|
(7,554 |
) |
|
|
(910 |
) |
|
Unrealized hedging losses
|
|
|
— |
|
|
|
561 |
|
|
|
— |
|
|
Other
|
|
|
— |
|
|
|
94 |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
| |
|
$ |
10,863 |
|
|
$ |
(1,223 |
) |
|
$ |
— |
|
| |
|
|
|
|
|
|
|
|
|
The components of deferred income tax assets and liabilities are
as follows (in thousands):
| |
|
|
|
|
|
|
|
|
|
|
|
| |
|
December 31, | |
| |
|
| |
| |
|
2004 | |
|
2003 | |
| |
|
| |
|
| |
| |
|
|
|
Restated | |
|
Deferred tax assets
|
|
|
|
|
|
|
|
|
| |
Current:
|
|
|
|
|
|
|
|
|
| |
|
Unrealized hedging losses
|
|
$ |
271 |
|
|
$ |
— |
|
| |
|
Derivative assets
|
|
|
11 |
|
|
|
— |
|
| |
|
Net operating loss carryforwards
|
|
|
— |
|
|
|
451 |
|
| |
|
|
|
|
|
|
| |
|
|
Current
|
|
|
282 |
|
|
|
451 |
|
| |
|
|
|
|
|
|
| |
Non-current:
|
|
|
|
|
|
|
|
|
| |
|
Net operating loss carryforwards
|
|
|
36,743 |
|
|
|
34,409 |
|
| |
|
Capital loss carryforwards
|
|
|
634 |
|
|
|
634 |
|
| |
|
Stock compensation
|
|
|
816 |
|
|
|
818 |
|
| |
|
Unrealized hedging losses
|
|
|
— |
|
|
|
561 |
|
| |
|
Derivative assets
|
|
|
— |
|
|
|
276 |
|
| |
|
Asset retirement obligations
|
|
|
1,014 |
|
|
|
812 |
|
| |
|
Preferred stock dividends as interest expense
|
|
|
— |
|
|
|
119 |
|
| |
|
Other
|
|
|
31 |
|
|
|
27 |
|
| |
|
|
|
|
|
|
| |
|
|
Non-current
|
|
|
39,238 |
|
|
|
37,656 |
|
| |
|
|
|
|
|
|
| |
|
|
39,520 |
|
|
|
38,107 |
|
| |
|
|
|
|
|
|
F-22
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
| |
|
|
|
|
|
|
|
|
|
|
|
| |
|
December 31, | |
| |
|
| |
| |
|
2004 | |
|
2003 | |
| |
|
| |
|
| |
| |
|
|
|
Restated | |
|
Deferred tax liabilities
|
|
|
|
|
|
|
|
|
| |
Current:
|
|
|
|
|
|
|
|
|
| |
|
Derivative liabilities
|
|
$ |
(28 |
) |
|
|
— |
|
| |
|
Gas imbalances
|
|
|
(15 |
) |
|
|
(144 |
) |
| |
|
|
|
|
|
|
| |
|
|
Current
|
|
|
(43 |
) |
|
|
(144 |
) |
| |
|
|
|
|
|
|
| |
Non-current:
|
|
|
|
|
|
|
|
|
| |
|
Depreciable and depletable property
|
|
|
(47,635 |
) |
|
|
(35,545 |
) |
| |
|
|
|
|
|
|
| |
|
|
(47,678 |
) |
|
|
(35,689 |
) |
| |
|
|
|
|
|
|
| |
|
Net deferred tax asset (liability)
|
|
|
(8,158 |
) |
|
|
2,418 |
|
| |
|
Valuation allowance
|
|
|
(634 |
) |
|
|
(634 |
) |
| |
|
|
|
|
|
|
| |
|
|
Total deferred tax asset (liability)
|
|
$ |
(8,792 |
) |
|
$ |
1,784 |
|
| |
|
|
|
|
|
|
|
Reflected in the accompanying balance sheets as:
|
|
|
|
|
|
|
|
|
| |
Current deferred income tax asset
|
|
$ |
239 |
|
|
$ |
307 |
|
| |
Non-current deferred income tax asset
|
|
|
— |
|
|
|
1,477 |
|
| |
Non-current deferred income tax liability
|
|
|
(9,031 |
) |
|
|
— |
|
| |
|
|
|
|
|
|
| |
|
$ |
(8,792 |
) |
|
$ |
1,784 |
|
| |
|
|
|
|
|
|
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.
Management 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. There was no change in the valuation
allowance for the year ended December 31, 2004.
At December 31, 2004, Brigham has regular tax NOLs of
approximately $105 million. Additionally, Brigham has
approximately $91.1 million of alternative minimum tax
(“AMT”) NOLs available as a deduction against future
taxable income. The NOLs expire from 2012 through 2024. The
value of these NOLs depends on the ability of Brigham to
generate taxable income. A summary of the NOLs follows (in
thousands):
| |
|
|
|
|
|
|
|
|
|
| |
|
Regular | |
|
AMT | |
| |
|
NOLs | |
|
NOLs | |
| |
|
| |
|
| |
|
Expiration Date:
|
|
|
|
|
|
|
|
|
| |
December 31, 2012
|
|
$ |
13,299 |
|
|
$ |
8,675 |
|
| |
December 31, 2018
|
|
|
26,411 |
|
|
|
23,170 |
|
| |
December 31, 2019
|
|
|
20,717 |
|
|
|
20,107 |
|
| |
December 31, 2020
|
|
|
12,491 |
|
|
|
7,566 |
|
| |
December 31, 2021
|
|
|
19,095 |
|
|
|
18,419 |
|
| |
December 31, 2022
|
|
|
4,452 |
|
|
|
4,114 |
|
| |
December 31, 2023
|
|
|
4,623 |
|
|
|
4,693 |
|
| |
December 31, 2024
|
|
|
3,893 |
|
|
|
4,329 |
|
| |
|
|
|
|
|
|
| |
|
$ |
104,981 |
|
|
$ |
91,073 |
|
| |
|
|
|
|
|
|
F-23
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
In addition, at December 31, 2004, Brigham has capital loss
carryforwards of approximately $1.8 million that expire in
varying years through 2007 in which Brigham has established a
valuation allowance.
Brigham believes an Internal Revenue Code Sec. 382 ownership
change may have occurred in March 2001, as a result of a
potential 50% change in ownership among its 5% shareholders over
a three-year period. The minimum amount of the limitation
approximates $5.2 million annually, which can be increased
by recognized Built-in-Gains over five years following the
ownership change. Management believes that the limitation will
not have a material impact on the utilization of its NOL’s.
9. 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, | |
| |
|
| |
| |
|
2004 | |
|
2003 | |
|
2002 | |
| |
|
| |
|
| |
|
| |
| |
|
|
|
Restated | |
|
Restated | |
| |
|
(In thousands, | |
| |
|
except per share amounts) | |
|
Basic EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Income (loss) available to common stockholders before
cumulative change in accounting principle
|
|
$ |
19,650 |
|
|
$ |
14,314 |
|
|
$ |
(676 |
) |
| |
Cumulative change in accounting principle
|
|
|
— |
|
|
|
268 |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
| |
|
Income (loss) available to common stockholders
|
|
$ |
19,650 |
|
|
$ |
14,582 |
|
|
$ |
(676 |
) |
| |
|
|
|
|
|
|
|
|
|
| |
|
Weighted average common shares outstanding
|
|
|
40,445 |
|
|
|
23,363 |
|
|
|
16,138 |
|
| |
|
|
|
|
|
|
|
|
|
| |
Basic EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Income (loss) available to common stockholders before
cumulative change in accounting principle
|
|
$ |
0.49 |
|
|
$ |
0.62 |
|
|
$ |
(0.04 |
) |
| |
Cumulative change in accounting principle
|
|
|
— |
|
|
|
0.01 |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
| |
|
Income (loss) available to common stockholders
|
|
$ |
0.49 |
|
|
$ |
0.63 |
|
|
$ |
(0.04 |
) |
| |
|
|
|
|
|
|
|
|
|
F-24
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, | |
| |
|
| |
| |
|
2004 | |
|
2003 | |
|
2002 | |
| |
|
| |
|
| |
|
| |
| |
|
|
|
Restated | |
|
Restated | |
|
Diluted EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Income (loss) available to common stockholders before
cumulative change in accounting principle
|
|
$ |
19,650 |
|
|
$ |
14,314 |
|
|
$ |
(676 |
) |
| |
Cumulative change in accounting principle
|
|
|
— |
|
|
|
268 |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
| |
|
Income (loss) available to common stockholders
|
|
|
19,650 |
|
|
|
14,582 |
|
|
|
(676 |
) |
| |
Adjustments for assumed conversions:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Dividends and accretion on mandatorily redeemable preferred
stock (1)
|
|
|
— |
|
|
|
3,290 |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
| |
|
|
19,650 |
|
|
|
3,290 |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
| |
Income (loss) available to common stockholders before
cumulative change in accounting principle — diluted
|
|
|
19,650 |
|
|
|
17,604 |
|
|
|
(676 |
) |
| |
Cumulative change in accounting principle
|
|
|
— |
|
|
|
268 |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
| |
|
Income (loss) available to common stockholders—diluted
|
|
$ |
19,650 |
|
|
$ |
17,872 |
|
|
$ |
(676 |
) |
| |
|
|
|
|
|
|
|
|
|
| |
Common shares outstanding
|
|
|
40,445 |
|
|
|
23,363 |
|
|
|
16,138 |
|
| |
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Warrants
|
|
|
— |
|
|
|
317 |
|
|
|
— |
|
| |
|
Mandatorily redeemable preferred stock
|
|
|
— |
|
|
|
9,971 |
|
|
|
— |
|
| |
|
Stock options
|
|
|
1,171 |
|
|
|
703 |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
| |
Potentially dilutive common shares
|
|
|
1,171 |
|
|
|
10,991 |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
| |
|
Adjusted common shares outstanding — diluted
|
|
|
41,616 |
|
|
|
34,354 |
|
|
|
16,138 |
|
| |
|
|
|
|
|
|
|
|
|
| |
Diluted EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Income (loss) available to common stockholders before
cumulative change in accounting principle
|
|
$ |
0.47 |
|
|
$ |
0.51 |
|
|
$ |
(0.04 |
) |
| |
Cumulative change in accounting principle
|
|
|
— |
|
|
|
0.01 |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
| |
|
Income (loss) available to common stockholders
|
|
$ |
0.47 |
|
|
$ |
0.52 |
|
|
$ |
(0.04 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
| (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, 2004, 2003, and 2002, potential dilution of
approximately 718,500, 1,000,000 and 14,300,000 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.
10. 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
F-25
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
not expect these matters to have a materially adverse effect on
the financial condition, results of operations or cash flows of
Brigham.
On November 20, 2001, Brigham filed a lawsuit in the
District Court of Travis County, Texas, against Steve Massey
Company, Inc. The Petition claimed Massey furnished defective
casing to Brigham, which ultimately led to the casing failure of
its Palmer 347 #5 well and the loss of the Palmer #5 as a
producing well. In 2004, the parties settled the case on terms
favorable to Brigham. Brigham received approximately $440,000 as
a result of this settlement. The amount of the settlement
reduced capitalized well cost. In addition, Massey agreed to
drop its $445,819 counterclaim.
On October 8, 2002, relatives of a contractor’s
employee filed a wrongful death action against Brigham and three
other contractors in the District Court of Matagorda County,
Texas in connection with the employee’s death on
Brigham’s Burkhart #1-R location. On March 23, 2004, a
jury determined that Brigham had no liability in the accidental
death of the contractor’s employee. The trial judge,
however, granted plaintiffs’ motion for a new trial.
Brigham expects the new trial to take place in June 2005.
Brigham believes it has adequate insurance to cover any
potential damage award (subject to a $5,000 deductible). At this
point in time, Brigham cannot predict the outcome of this case.
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, claiming
that contractor breached its contract with Brigham and
negligently performed services on the well. Brigham believes the
contractor’s actions damaged Brigham by approximately
$650,000. The contractor counterclaimed, claiming it is entitled
to recover approximately $315,000. In April 2004, the parties
settled the case, resulting in a payment by the contractor to
its co-participants and Brigham of $325,000. In addition, the
contractor dropped 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 did not receive any incremental recovery as a result of
the settlement.
Prior to drilling, the operator of the Stonehocker #1 well
disputed Brigham’s 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
Brigham’s 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 reviewed the reports of the
Referee and the original Administrative Law Judge and affirmed
those rulings. The operator then filed an appeal with the
Oklahoma Supreme Court. In January 2005, the parties settled the
dispute. The operator agreed to recognize Brigham’s full
interest in the Stonehocker well, and also agreed to reverse
certain charges made under the operating agreements of six
additional wells in which Brigham owns an interest.
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 asserted that it did not relinquish
its entire interest, but rather became subject only to a
400 percent payout provision. In November 2003, this
company filed a lawsuit in the District Court of Brazoria
County, Texas, against Brigham for breach of contract. If the
suit was successful, it could have resulted in a judgment of as
much as $700,000. In April 2004, Brigham settled the case,
agreeing to pay the company $350,000 in return for the
company’s assignment of all its right, title and interest
in the unit for the well.
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 denied any wrongdoing
and asserted a counterclaim against Brigham for alleged tortuous
interference with an existing business relationship between the
company and its employee. In April 2004, Brigham settled the
F-26
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
case. The company agreed not to compete against Brigham in a
specified area for two years, assigned Brigham a small
overriding royalty in three tracts, paid Brigham $50,000, and
dropped its counterclaim.
As of December 31, 2004, 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.
|
|
|
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 2012. The future
minimum annual rental payments under the noncancelable terms of
these leases at December 31, 2004 are as follows (in
thousands):
| |
|
|
|
|
|
2005
|
|
$ |
692 |
|
|
2006
|
|
|
709 |
|
|
2007
|
|
|
698 |
|
|
2008
|
|
|
687 |
|
|
2009
|
|
|
704 |
|
|
Thereafter
|
|
|
1,836 |
|
| |
|
|
|
| |
|
$ |
5,326 |
|
| |
|
|
|
Future minimum rental payments are not reduced by sublease
rental income of approximately $69,000, and $44,000 due in 2005
and 2006, respectively, under noncancelable subleases.
Rental expense for the years ended December 31, 2004, 2003
and 2002 was approximately $754,000, $851,000 and $868,000,
respectively.
The following purchasers accounted for 10% or more of
Brigham’s oil and natural gas sales for the years ended
December 31, 2004, 2003 and 2002:
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
2004 | |
|
2003 | |
|
2002 | |
| |
|
| |
|
| |
|
| |
|
Purchaser A
|
|
|
— |
|
|
|
— |
|
|
|
19 |
% |
|
Purchaser B
|
|
|
11 |
% |
|
|
— |
|
|
|
— |
|
|
Purchaser C
|
|
|
12 |
% |
|
|
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.
|
|
| 11. |
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) reduce commodity price
F-27
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
risk and (iii) provide a base level of cash flow in order
to assure it can execute at least a portion of its capital
spending plans.
|
|
|
Natural Gas and Crude Oil Derivative Contracts |
Brigham’s cash-flow hedges consisted of fixed-price swaps
and costless collars (purchased put options and written call
options). The fixed-price swap agreements are used to fix the
prices of anticipated future oil and natural gas production. The
costless collars are used to establish floor and ceiling prices
on anticipated future oil and natural gas production. There were
no net premiums received when Brigham entered into these option
agreements. As of December 31, 2004, Brigham had entered
into derivative contracts that qualify as cash flow hedges with
respect to future production as follows:
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
2005 | |
| |
|
| |
| |
|
First | |
|
Second | |
|
Third | |
|
Fourth | |
| |
|
Quarter | |
|
Quarter | |
|
Quarter | |
|
Quarter | |
| |
|
| |
|
| |
|
| |
|
| |
|
Natural gas collars:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (MMbtu)
|
|
|
727,500 |
|
|
|
635,000 |
|
|
|
180,000 |
|
|
|
60,000 |
|
|
Average price ($ per MMBtu)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
$ |
5.164 |
|
|
$ |
4.931 |
|
|
$ |
5.450 |
|
|
$ |
5.450 |
|
|
Ceiling
|
|
|
7.256 |
|
|
|
7.077 |
|
|
|
8.000 |
|
|
|
8.000 |
|
|
Crude oil collars:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (Bbls)
|
|
|
27,450 |
|
|
|
18,655 |
|
|
|
— |
|
|
|
— |
|
|
Average price ($ per Bbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
$ |
25.56 |
|
|
$ |
26.80 |
|
|
$ |
— |
|
|
$ |
— |
|
|
Ceiling
|
|
|
30.18 |
|
|
|
32.51 |
|
|
|
— |
|
|
|
— |
|
The following table summarizes the hedging contracts to which
Brigham entered subsequent to December 31, 2004, the total
natural gas and crude oil production volumes subject to those
contacts and the weighted average NYMEX reference price for
those volumes:
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
2005 | |
|
2006 | |
| |
|
| |
|
| |
| |
|
Third | |
|
Fourth | |
|
First | |
| |
|
Quarter | |
|
Quarter | |
|
Quarter | |
| |
|
| |
|
| |
|
| |
|
Natural gas collars:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (MMbtu)
|
|
|
300,000 |
|
|
|
200,000 |
|
|
|
150,000 |
|
|
Average price ($ per MMBtu)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
$ |
6.000 |
|
|
$ |
6.380 |
|
|
$ |
6.750 |
|
|
Ceiling
|
|
|
7.200 |
|
|
|
8.000 |
|
|
|
8.800 |
|
|
Crude oil collars:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (Bbls)
|
|
|
15,000 |
|
|
|
15,000 |
|
|
|
— |
|
|
Average price ($ per Bbl)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Floor
|
|
$ |
40.00 |
|
|
$ |
40.00 |
|
|
$ |
— |
|
|
Ceiling
|
|
|
53.00 |
|
|
|
53.00 |
|
|
|
— |
|
F-28
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
The fair value of derivative 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, | |
| |
|
| |
| |
|
2004 | |
|
2003 | |
| |
|
| |
|
| |
|
Other current liabilities
|
|
$ |
870 |
|
|
$ |
2,141 |
|
|
Other noncurrent liabilities
|
|
|
1 |
|
|
|
40 |
|
|
Other current assets
|
|
|
142 |
|
|
|
— |
|
|
Other noncurrent assets
|
|
|
3 |
|
|
|
3 |
|
| |
|
|
|
|
|
|
| |
Net fair value of derivative contracts
|
|
$ |
726 |
|
|
$ |
2,178 |
|
| |
|
|
|
|
|
|
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, 2004:
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, | |
| |
|
| |
| |
|
2004 | |
|
2003 | |
|
2002 | |
| |
|
| |
|
| |
|
| |
|
Natural gas
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Average price per Mcf as reported (including hedging results)
|
|
$ |
5.84 |
|
|
$ |
4.92 |
|
|
$ |
3.21 |
|
| |
Average price per Mcf realized (excluding hedging results)
|
|
$ |
6.05 |
|
|
$ |
5.68 |
|
|
$ |
3.33 |
|
| |
Decrease in revenue (in thousands)
|
|
$ |
1,853 |
|
|
$ |
4,807 |
|
|
$ |
712 |
|
|
Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Average price per Bbl as reported (including hedging results)
|
|
$ |
35.17 |
|
|
$ |
28.17 |
|
|
$ |
23.55 |
|
| |
Average price per Bbl realized (excluding hedging results)
|
|
$ |
40.13 |
|
|
$ |
30.79 |
|
|
$ |
25.17 |
|
| |
Decrease in revenue (in thousands)
|
|
$ |
2,841 |
|
|
$ |
1,885 |
|
|
$ |
1,135 |
|
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.
As of December 31, 2004, Brigham’s derivative
positions included an option contract that is not designated as
a hedge. This contract was entered into to offset the cost of
other options that are designated as hedges.
| |
|
|
|
|
| |
|
2005 | |
| |
|
| |
| |
|
First | |
| |
|
Quarter | |
| |
|
| |
|
Natural gas written puts:
|
|
|
|
|
|
Volumes (MMbtu)
|
|
|
210,000 |
|
|
Average price ($ per MMBtu)
|
|
$ |
5.500 |
|
F-29
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
The following table summarizes option contracts not designated
as hedges to which Brigham entered subsequent to
December 31, 2004:
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
2005 | |
|
2006 | |
| |
|
| |
|
| |
| |
|
Third | |
|
Fourth | |
|
First | |
| |
|
Quarter | |
|
Quarter | |
|
Quarter | |
| |
|
| |
|
| |
|
| |
|
Natural gas written puts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (MMbtu)
|
|
|
300,000 |
|
|
|
200,000 |
|
|
|
150,000 |
|
|
Average price ($ per MMBtu)
|
|
$ |
5.000 |
|
|
$ |
5.250 |
|
|
$ |
5.500 |
|
|
Crude oil written puts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (MMbtu)
|
|
|
15,000 |
|
|
|
15,000 |
|
|
|
— |
|
|
Average price ($ per MMBtu)
|
|
$ |
30.000 |
|
|
$ |
30.000 |
|
|
$ |
— |
|
The following table sets forth the recognized non-cash gains
(losses) related to changes in the fair values of derivative
instruments that do not qualify as hedging contracts and gains
(losses) related to the cash settlement payments made by Brigham
to the counterparty for the three year period ended
December 31, 2004:
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, | |
| |
|
| |
| |
|
2004 | |
|
2003 |
|
2002 | |
| |
|
| |
|
|
|
| |
|
Non-cash gains (losses)
|
|
$ |
(33 |
) |
|
$ |
— |
|
|
$ |
384 |
|
|
Losses from cash settlements
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
(559 |
) |
For the years ended December 31, 2004, 2003 and 2002,
ineffectiveness associated with Brigham’s derivative
commodity instruments designated as cash flow hedges increased
(decreased) earnings by approximately $0.7 million,
$(0.7) million and $(0.1) million, respectively. These
amounts are included in other income and expense.
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.
At December 31, 2004, Brigham had an interest rate swap
contract to pay a fixed-rate of interest of 7.61% on
$20.0 million notional amount of senior subordinated notes.
The $20.0 million notional amount of the outstanding
contract matures in March 2009. As of December 31, 2004,
approximately $1,000 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.
F-30
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
|
|
| 12. |
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,
2004 and 2003 was $20 million and $20.1 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, 2004 and
2003 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.
|
|
| 13. |
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 2004, 2003 and 2002, 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 25.25%, 47% and 62.5% of eligible employee
contributions made during 2004, 2003 and 2002, respectively.
Brigham contributed approximately $204,000, $250,000 and
$236,000 to the 401(k) plan for the years ended
December 31, 2004, 2003 and 2002, respectively, to match
eligible contributions by employees.
|
|
| 14. |
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.
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
F-31
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
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 option activity under the
incentive plans for each of the three years ended
December 31, 2004:
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
2004 |
|
2003 |
|
2002 |
| |
|
|
|
|
|
|
| |
|
|
|
Weighted- |
|
|
|
Weighted- |
|
|
|
Weighted- |
| |
|
|
|
Average |
|
|
|
Average |
|
|
|
Average |
| |
|
|
|
Exercise |
|
|
|
Exercise |
|
|
|
Exercise |
| |
|
Shares |
|
Price |
|
Shares |
|
Price |
|
Shares |
|
Price |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Options outstanding at beginning of year
|
|
|
2,582,675 |
|
|
$ |
4.78 |
|
|
|
1,788,135 |
|
|
$ |
3.00 |
|
|
|
1,616,771 |
|
|
$ |
3.00 |
|
| |
Granted
|
|
|
790,000 |
|
|
|
8.75 |
|
|
|
1,127,500 |
|
|
|
6.46 |
|
|
|
481,000 |
|
|
|
4.12 |
|
| |
Forfeited or cancelled
|
|
|
(80,894 |
) |
|
|
(4.72 |
) |
|
|
(23,200 |
) |
|
|
(3.49 |
) |
|
|
(177,129 |
) |
|
|
(3.25 |
) |
| |
Exercised
|
|
|
(314,181 |
) |
|
|
(3.06 |
) |
|
|
(309,760 |
) |
|
|
(2.68 |
) |
|
|
(132,507 |
) |
|
|
(2.23 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options outstanding at end of year
|
|
|
2,977,600 |
|
|
$ |
6.01 |
|
|
|
2,582,675 |
|
|
$ |
4.78 |
|
|
|
1,788,135 |
|
|
$ |
3.00 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options exercisable at end of year
|
|
|
792,557 |
|
|
$ |
4.30 |
|
|
|
656,633 |
|
|
$ |
3.14 |
|
|
|
658,126 |
|
|
$ |
2.79 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brigham is required to use variable accounting for 252,500 of
the stock options granted during 2000 of which 118,000 remain
outstanding at December 31, 2004. 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.
The following table summarizes information about stock options
outstanding at December 31, 2004:
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Options Outstanding |
|
Options Exercisable |
| |
|
|
|
|
| |
|
Number |
|
Weighted- |
|
|
|
Number |
|
|
| |
|
Outstanding at |
|
Average |
|
Weighted- |
|
Exercisable at |
|
Weighted- |
| |
|
December 31, |
|
Remaining |
|
Average |
|
December 31, |
|
Average |
| Exercise Price |
|
2004 |
|
Contractual Life |
|
Exercise Price |
|
2004 |
|
Exercise Price |
| |
|
|
|
|
|
|
|
|
|
|
|
$1.55 to $1.83
|
|
|
119,000 |
|
|
|
1.1 years |
|
|
$ |
1.83 |
|
|
|
81,000 |
|
|
$ |
1.83 |
|
|
2.38 to 3.41
|
|
|
400,100 |
|
|
|
3.8 years |
|
|
|
3.27 |
|
|
|
189,491 |
|
|
|
3.18 |
|
|
3.61 to 5.19
|
|
|
691,000 |
|
|
|
4.1 years |
|
|
|
4.12 |
|
|
|
320,733 |
|
|
|
4.05 |
|
|
6.31 to 6.73
|
|
|
935,000 |
|
|
|
5.7 years |
|
|
|
6.68 |
|
|
|
189,333 |
|
|
|
6.67 |
|
|
7.88 to 14.38
|
|
|
832,500 |
|
|
|
6.7 years |
|
|
|
8.75 |
|
|
|
12,000 |
|
|
|
7.97 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$1.55 to $14.38
|
|
|
2,977,600 |
|
|
|
5.2 years |
|
|
$ |
6.01 |
|
|
|
792,557 |
|
|
$ |
4.30 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
During the years ended December 31, 2004 and 2003, Brigham
issued 70,000 and 350,000, respectively, restricted shares of
common stock as compensation to officers and key employees of
Brigham. The restricted shares vest over five years. Brigham
recognized approximately $0.5 million and $1.8 million
F-32
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
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 years ended December
31:
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended |
|
Year Ended |
| |
|
December 31, 2004 |
|
December 31, 2003 |
| |
|
|
|
|
| |
|
|
|
Weighted- |
|
|
|
Weighted- |
| |
|
Number of |
|
Average |
|
Number of |
|
Average |
| |
|
Shares |
|
Price |
|
Shares |
|
Price |
| |
|
|
|
|
|
|
|
|
|
Restricted Stock Awards:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Restricted shares outstanding at the beginning of the year
|
|
|
350,000 |
|
|
$ |
5.23 |
|
|
|
— |
|
|
$ |
— |
|
| |
Shares granted
|
|
|
70,000 |
|
|
|
7.35 |
|
|
|
350,000 |
|
|
|
5.23 |
|
| |
Lapse of restrictions
|
|
|
(72,083 |
) |
|
|
(5.23 |
) |
|
|
— |
|
|
|
— |
|
| |
Forfeitures
|
|
|
(22,917 |
) |
|
|
(5.69 |
) |
|
|
— |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Restricted shares outstanding at the end of the year
|
|
|
325,000 |
|
|
$ |
5.65 |
|
|
|
350,000 |
|
|
$ |
5.23 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 15. |
Related Party Transactions |
During the years ended December 31, 2004, 2003, and 2002,
Brigham incurred costs of approximately $2.9 million,
$2.0 million and $1.1 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, 2004 and 2003, Brigham had
recorded a liability in accounts payable of approximately
$236,000 and $262,000, 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, $30,000, and $45,000 for the years ended
December 31, 2004, 2003, and 2002, respectively. Additional
disbursements totaling approximately $12,000 were made during
each of the years ended December 31, 2004, 2003, and 2002,
for the reimbursement of certain expenses. At December 31,
2004 and 2003, there were no payables related to these services
recorded by Brigham.
At December 31, 2004 and 2003 Brigham had short-term
accounts receivable from Mr. Steven Webster, a director of
Brigham, of approximately $2,200 and $8,300, 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. During 2004, Brigham
did not sell any oil or natural gas to Citation Crude Marketing,
Inc.
F-33
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
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 2004, 2003 and 2002 were $3.5 million,
$1.2 million and $0.4 million, respectively. Brigham
owed the drilling company approximately $0.7 million and
$0.3 million at December 31, 2004 and 2003,
respectively.
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 2004,
2003 and 2002 were $1 million, $478,000 and $130,000,
respectively. At December 31, 2004 and 2003, Brigham owed
the service company approximately $132,000 and $237,000,
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, 2004 and 2003, Brigham was owed $114,000
and $206,000, respectively, by Carrizo for exploration and
production activities. Brigham owed Carrizo $0 and $50,000 at
December 31, 2004 and 2003, 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. There were no amounts paid to Aspect during 2004 and 2003.
Total amounts paid to Aspect during 2002 for exploration,
development and production operations were $189,000. Total
amounts paid to Brigham by Aspect, or on their behalf, during
2004, 2003 and 2002 for exploration, development and production
operations were $191,000, $91,000 and $1,008,000, respectively.
There were no amounts owed by Brigham to Aspect at
December 31, 2004 or 2003. Aspect owed Brigham $136,000 and
$69,000 at December 31, 2004 and 2003, respectively, for
various oil and gas exploration and production activities.
F-34
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS —
(Continued)
|
|
| 16. |
Supplemental Cash Flow Information |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, |
| |
|
|
| |
|
2004 |
|
2003 |
|
2002 |
| |
|
|
|
|
|
|
|
Cash paid for interest
|
|
$ |
1,634 |
|
|
$ |
2,447 |
|
|
$ |
3,974 |
|
|
Noncash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Dividends and accretion on mandatorily redeemable preferred stock
|
|
|
726 |
|
|
|
3,448 |
|
|
|
2,952 |
|
| |
Capitalized asset retirement obligations
|
|
|
512 |
|
|
|
1,630 |
|
|
|
— |
|
| |
Conversion 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
|
|
|
514 |
|
|
|
1,831 |
|
|
|
— |
|
| |
Forfeitures of restricted stock
|
|
|
131 |
|
|
|
— |
|
|
|
— |
|
| |
Issuance of stock options
|
|
|
— |
|
|
|
296 |
|
|
|
— |
|
|
|
| 17. |
Other Assets and Liabilities |
Other current assets consist of the following (in thousands):
| |
|
|
|
|
|
|
|
|
| |
|
December 31, |
| |
|
|
| |
|
2004 |
|
2003 |
| |
|
|
|
|
|
Gas imbalance receivables
|
|
$ |
— |
|
|
$ |
2,477 |
|
|
Other
|
|
|
901 |
|
|
|
1,129 |
|
| |
|
|
|
|
|
|
|
|
| |
|
$ |
901 |
|
|
$ |
3,606 |
|
| |
|
|
|
|
|
|
|
|
Other current liabilities consist of the following (in
thousands):
| |
|
|
|
|
|
|
|
|
| |
|
December 31 |
| |
|
|
| |
|
2004 |
|
2003 |
| |
|
|
|
|
|
Derivative liabilities
|
|
$ |
870 |
|
|
$ |
2,141 |
|
|
Gas imbalance liabilities
|
|
|
— |
|
|
|
2,064 |
|
|
Other
|
|
|
1,355 |
|
|
|
1,193 |
|
| |
|
|
|
|
|
|
|
|
| |
|
$ |
2,225 |
|
|
$ |
5,398 |
|
| |
|
|
|
|
|
|
|
|
Gas imbalance receivables and liabilities were settled with the
counterparty during 2004.
F-35
BRIGHAM EXPLORATION COMPANY
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
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, |
| |
|
|
| |
|
2004 |
|
2003 |
|
2002 |
| |
|
|
|
|
|
|
|
Costs incurred for the year:
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Exploration (including geological and geophysical costs)
|
|
$ |
30,189 |
|
|
$ |
20,126 |
|
|
$ |
12,693 |
|
| |
Property acquisition
|
|
|
6,226 |
|
|
|
4,850 |
|
|
|
2,510 |
|
| |
Development
|
|
|
50,497 |
|
|
|
22,285 |
|
|
|
13,301 |
|
| |
Asset retirement obligations
|
|
|
513 |
|
|
|
269 |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
$ |
87,425 |
|
|
$ |
47,530 |
|
|
$ |
28,504 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
Following is a summary of capitalized costs (in thousands)
excluded from depletion at December 31, 2004 by year
incurred. Excluded costs for prospects are accumulated by year.
When circumstances dictate that less than the entire prospect
should be removed from excluded costs, Brigham uses a
proportionate method that removes amounts from each year, as
opposed to a first-in-first-out method. Costs are reflected in
the full cost pool as the drilling program is executed or as
costs are evaluated and deemed impaired. 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, |
|
|
|
|
| |
|
|
|
Prior |
|
|
| |
|
2004 |
|
2003 |
|
2002 |
|
Years |
|
Total |
| |
|
|
|
|
|
|
|
|
|
|
|
Property acquisition
|
|
$ |
2,583 |
|
|
$ |
1,525 |
|
|
$ |
643 |
|
|
$ |
10,879 |
|
|
$ |
15,630 |
|
|
Exploration (including geological and geophysical costs)
|
|
|
8,339 |
|
|
|
2,268 |
|
|
|
856 |
|
|
|
14,905 |
|
|
|
26,368 |
|
|
Drilling
|
|
|
3,100 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
3,100 |
|
|
Capitalized interest
|
|
|
250 |
|
|
|
163 |
|
|
|
72 |
|
|
|
1,773 |
|
|
|
2,258 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Total
|
|
$ |
14,272 |
|
|
$ |
3,956 |
|
|
$ |
1,571 |
|
|
$ |
27,557 |
|
|
$ |
47,356 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Natural Gas Reserves and Related Financial Data
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
F-36
BRIGHAM EXPLORATION COMPANY
SUPPLEMENTAL OIL AND GAS INFORMATION
(UNAUDITED) — (Continued)
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.
| |
|
|
|
|
|
|
|
|
|
| |
|
Natural |
|
|
| |
|
Gas |
|
Oil |
| |
|
(MMcf) |
|
(MBbls) |
| |
|
|
|
|
|
Proved reserves at December 31, 2001
|
|
|
88,594 |
|
|
|
3,748 |
|
| |
Revisions of previous estimates
|
|
|
(824 |
) |
|
|
(31 |
) |
| |
Extensions, discoveries and other additions
|
|
|
18,005 |
|
|
|
599 |
|
| |
Sales of minerals-in-place
|
|
|
(556 |
) |
|
|
(8 |
) |
| |
Production
|
|
|
(5,791 |
) |
|
|
(701 |
) |
| |
|
|
|
|
|
|
|
|
|
Proved reserves at December 31, 2002
|
|
|
99,428 |
|
|
|
3,607 |
|
| |
Revisions of previous estimates
|
|
|
(6,148 |
) |
|
|
176 |
|
| |
Extensions, discoveries and other additions
|
|
|
22,479 |
|
|
|
1,067 |
|
| |
Production
|
|
|
(6,356 |
) |
|
|
(720 |
) |
| |
|
|
|
|
|
|
|
|
|
Proved reserves at December 31, 2003
|
|
|
109,403 |
|
|
|
4,130 |
|
| |
Revisions of previous estimates
|
|
|
(11,142 |
) |
|
|
(642 |
) |
| |
Extensions, discoveries and other additions
|
|
|
12,444 |
|
|
|
321 |
|
| |
Production
|
|
|
(8,830 |
) |
|
|
(573 |
) |
| |
|
|
|
|
|
|
|
|
|
Proved reserves at December 31, 2004
|
|
|
101,875 |
|
|
|
3,236 |
|
| |
|
|
|
|
|
|
|
|
|
Proved developed reserves at December 31:
|
|
|
|
|
|
|
|
|
| |
2001
|
|
|
38,633 |
|
|
|
2,609 |
|
| |
2002
|
|
|
42,161 |
|
|
|
2,330 |
|
| |
2003
|
|
|
49,920 |
|
|
|
2,863 |
|
| |
2004
|
|
|
47,494 |
|
|
|
2,124 |
|
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. The effects of
hedging activities are insignificant to the standardized measure
of discounted future net cash flows.
F-37
BRIGHAM EXPLORATION COMPANY
SUPPLEMENTAL OIL AND GAS INFORMATION
(UNAUDITED) — (Continued)
| |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
December 31, |
| |
|
|
| |
|
2004 |
|
2003 |
|
2002 |
| |
|
|
|
|
|
|
|
Future cash inflows
|
|
$ |
766,344 |
|
|
$ |
737,544 |
|
|
$ |
601,081 |
|
|
Future production costs
|
|
|
(159,697 |
) |
|
|
(123,176 |
) |
|
|
(82,689 |
) |
|
Future development costs
|
|
|
(79,868 |
) |
|
|
(58,978 |
) |
|
|
(48,668 |
) |
|
Future income tax expense
|
|
|
(116,254 |
) |
|
|
(138,118 |
) |
|
|
(104,724 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash inflows
|
|
|
410,525 |
|
|
|
417,272 |
|
|
|
365,000 |
|
|
10% annual discount for estimated timing of cash flows
|
|
|
(170,816 |
) |
|
|
(155,674 |
) |
|
|
(125,302 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$ |
239,709 |
|
|
$ |
261,598 |
|
|
$ |
239,698 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
The base sales prices for Brigham’s reserve estimates were
as follows:
| |
|
|
|
|
|
|
|
|
| |
|
Natural |
|
|
| |
|
Gas |
|
Oil |
| |
|
(MMbtu) |
|
(Bbl) |
| |
|
|
|
|
|
December 31, 2004
|
|
$ |
6.19 |
|
|
$ |
43.46 |
|
|
December 31, 2003
|
|
|
5.83 |
|
|
|
32.55 |
|
|
December 31, 2002
|
|
|
4.74 |
|
|
|
31.25 |
|
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.
Changes in the future net cash inflows discounted at 10% per
annum follow (in thousands):
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
December 31, |
| |
|
|
| |
|
2004 |
|
2003 |
|
2002 |
| |
|
|
|
|
|
|
|
Beginning of period
|
|
$ |
261,598 |
|
|
$ |
239,698 |
|
|
$ |
120,924 |
|
| |
Sales of oil and natural gas produced, net of production costs
|
|
|
(67,992 |
) |
|
|
(51,126 |
) |
|
|
(31,475 |
) |
| |
Previously estimated development costs incurred during the period
|
|
|
37,109 |
|
|
|
14,370 |
|
|
|
8,625 |
|
| |
Extensions and discoveries
|
|
|
27,089 |
|
|
|
91,383 |
|
|
|
60,872 |
|
| |
Sales of minerals-in-place
|
|
|
— |
|
|
|
— |
|
|
|
(1,064 |
) |
| |
Net change of prices and production costs
|
|
|
38,501 |
|
|
|
20,822 |
|
|
|
136,808 |
|
| |
Change in future development costs
|
|
|
(40,086 |
) |
|
|
(11,281 |
) |
|
|
(8,000 |
) |
| |
Changes in production rates (timing)
|
|
|
(33,270 |
) |
|
|
(40,103 |
) |
|
|
(19,539 |
) |
| |
Revisions of previous quantity estimates
|
|
|
(47,324 |
) |
|
|
(15,063 |
) |
|
|
(2,876 |
) |
| |
Accretion of discount
|
|
|
34,381 |
|
|
|
30,737 |
|
|
|
14,681 |
|
| |
Change in income taxes
|
|
|
27,452 |
|
|
|
(14,537 |
) |
|
|
(41,794 |
) |
| |
Other
|
|
|
2,251 |
|
|
|
(3,302 |
) |
|
|
2,536 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
End of period
|
|
$ |
239,709 |
|
|
$ |
261,598 |
|
|
$ |
239,698 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
F-38
BRIGHAM EXPLORATION COMPANY
SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION
Quarterly Financial Data (Unaudited)
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, 2004 |
| |
|
|
| |
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
| |
|
1 |
|
2 |
|
3 |
|
4 |
| |
|
|
|
|
|
|
|
|
| |
|
Restated |
|
Restated |
|
Restated |
|
|
|
Revenue
|
|
$ |
16,820 |
|
|
$ |
17,957 |
|
|
$ |
17,267 |
|
|
$ |
20,184 |
|
|
Operating income
|
|
|
7,986 |
|
|
|
8,809 |
|
|
|
7,561 |
|
|
|
8,475 |
|
|
Net income
|
|
|
4,925 |
|
|
|
5,138 |
|
|
|
4,491 |
|
|
|
5,096 |
|
|
Net income per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Basic
|
|
$ |
0.13 |
|
|
$ |
0.13 |
|
|
$ |
0.11 |
|
|
$ |
0.12 |
|
| |
Diluted
|
|
$ |
0.12 |
|
|
$ |
0.13 |
|
|
$ |
0.11 |
|
|
$ |
0.12 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, 2003 |
| |
|
|
| |
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
| |
|
1 |
|
2 |
|
3 |
|
4 |
| |
|
|
|
|
|
|
|
|
| |
|
Restated |
|
Restated |
|
Restated |
|
Restated |
|
Revenue
|
|
$ |
14,677 |
|
|
$ |
12,170 |
|
|
$ |
13,213 |
|
|
$ |
11,617 |
|
|
Operating income
|
|
|
7,274 |
|
|
|
4,607 |
|
|
|
5,307 |
|
|
|
4,722 |
|
|
Net income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Income available to common stockholders before cumulative effect
of change in accounting principle
|
|
|
5,129 |
|
|
|
2,081 |
|
|
|
3,060 |
|
|
|
4,044 |
|
| |
Cumulative effect of change in accounting principle
|
|
|
268 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Net income available to common stockholders
|
|
$ |
5,397 |
|
|
$ |
2,081 |
|
|
$ |
3,060 |
|
|
$ |
4,044 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Basic:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Income available to common stockholders before cumulative effect
of change in accounting principle
|
|
$ |
0.26 |
|
|
$ |
0.12 |
|
|
$ |
0.14 |
|
|
$ |
0.13 |
|
| |
|
Cumulative effect of change in accounting principle
|
|
|
0.01 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Net income available to common stockholders
|
|
$ |
0.27 |
|
|
$ |
0.12 |
|
|
$ |
0.14 |
|
|
$ |
0.13 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Diluted:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Income available to common stockholders before cumulative effect
of change in accounting principle
|
|
$ |
0.19 |
|
|
$ |
0.09 |
|
|
$ |
0.12 |
|
|
$ |
0.12 |
|
| |
|
Cumulative effect of change in accounting principle
|
|
|
0.01 |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Net income available to common stockholders
|
|
$ |
0.20 |
|
|
$ |
0.09 |
|
|
$ |
0.12 |
|
|
$ |
0.12 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-39
BRIGHAM EXPLORATION COMPANY
SUPPLEMENTAL QUARTERLY FINANCIAL
INFORMATION — (Continued)
The information in the quarterly data below represents only
those consolidated statements of operations line items affected
by the restatement.
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, 2004 | |
| |
|
| |
| |
|
Quarter 1 | |
|
Quarter 2 | |
|
Quarter 3 | |
| |
|
| |
|
| |
|
| |
| |
|
As Reported | |
|
Restated | |
|
As Reported | |
|
Restated | |
|
As Reported | |
|
Restated | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
| |
|
(Unaudited) | |
|
Consolidated Statements of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Depletion of oil and natural gas properties
|
|
$ |
4,880 |
|
|
$ |
5,124 |
|
|
$ |
5,623 |
|
|
$ |
5,524 |
|
|
$ |
5,871 |
|
|
$ |
5,860 |
|
| |
Deferred income tax benefit (expense)
|
|
|
(2,500 |
) |
|
|
(2,420 |
) |
|
|
(2,683 |
) |
|
|
(2,714 |
) |
|
|
(2,051 |
) |
|
|
(2,056 |
) |
| |
Net income (loss) available to common stockholders
|
|
|
5,089 |
|
|
|
4,925 |
|
|
|
5,070 |
|
|
|
5,138 |
|
|
|
4,485 |
|
|
|
4,491 |
|
| |
Net income (loss) per share available to common stockholders:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Basic
|
|
$ |
0.13 |
|
|
$ |
0.13 |
|
|
$ |
0.13 |
|
|
$ |
0.13 |
|
|
$ |
0.11 |
|
|
$ |
0.11 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Diluted
|
|
$ |
0.13 |
|
|
$ |
0.12 |
|
|
$ |
0.13 |
|
|
$ |
0.13 |
|
|
$ |
0.11 |
|
|
$ |
0.11 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Year Ended December 31, 2003 | |
| |
|
| |
| |
|
Quarter 1 | |
|
Quarter 2 | |
|
Quarter 3 | |
|
Quarter 4 | |
| |
|
| |
|
| |
|
| |
|
| |
| |
|
As reported | |
|
Restated | |
|
As reported | |
|
Restated | |
|
As reported | |
|
Restated | |
|
As reported | |
|
Restated | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
| |
|
(Unaudited) | |
|
Consolidated Statements of Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Depletion of oil and natural gas properties
|
|
$ |
4,102 |
|
|
$ |
4,221 |
|
|
$ |
3,799 |
|
|
$ |
4,103 |
|
|
$ |
3,952 |
|
|
$ |
4,235 |
|
|
$ |
5,119 |
|
|
$ |
4,260 |
|
| |
Deferred income tax benefit (expense)
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
1,636 |
|
|
|
1,223 |
|
| |
Net income (loss) available to common stockholders
|
|
|
5,516 |
|
|
|
5,397 |
|
|
|
2,385 |
|
|
|
2,081 |
|
|
|
3,343 |
|
|
|
3,060 |
|
|
|
3,598 |
|
|
|
4,044 |
|
|
Net income (loss) per share available to common stockholders:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Basic
|
|
$ |
0.28 |
|
|
$ |
0.27 |
|
|
$ |
0.12 |
|
|
$ |
0.12 |
|
|
$ |
0.16 |
|
|
$ |
0.14 |
|
|
$ |
0.11 |
|
|
$ |
0.13 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Diluted
|
|
$ |
0.20 |
|
|
$ |
0.20 |
|
|
$ |
0.10 |
|
|
$ |
0.09 |
|
|
$ |
0.13 |
|
|
$ |
0.12 |
|
|
$ |
0.10 |
|
|
$ |
0.12 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-40
INDEX TO EXHIBITS
| |
|
|
|
|
|
|
| Number | |
|
|
|
Description |
| | |
|
|
|
|
| |
3.1 |
|
|
— |
|
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). |
| |
4.5 |
|
|
— |
|
Certificate of Elimination of Certificate of Designations of
Series B Preferred Stock of Brigham Exploration Company,
dated June 4, 2004, (filed as Exhibit 99.2 to
Brigham’s Current Report on Form 8-K (filed
July 20, 2004), 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. (filed as
Exhibit 10.4 to Brigham’s Annual Report on
Form 10-K for the year ended December 31, 2003 and
incorporated herein by reference |
| |
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). |
| |
|
|
|
|
|
|
| Number | |
|
|
|
Description |
| | |
|
|
|
|
| |
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). |
| |
10.13† |
|
|
— |
|
Third Amendment to Two Bridge Point Lease Agreement dated
November 1998 between Hub Properties Trust and Brigham
Oil & Gas, L.P. |
| |
10.14† |
|
|
— |
|
Fourth Amendment to Two Bridge Point Lease Agreement dated
February 7, 2002 between Hub Properties Trust and Brigham
Oil & Gas, L.P. |
| |
10.15† |
|
|
— |
|
Fifth Amendment to Two Bridge Point Lease Agreement dated
December 20, 2004 between Hub Properties Trust, a Maryland
real estate investment trust, and Brigham Oil & Gas,
L.P. |
| |
10.16 |
|
|
— |
|
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). |
| |
10.17 |
|
|
— |
|
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). |
| |
10.18* |
|
|
— |
|
1997 Director Stock Option Plan, as amended as of
April 9, 2003. (filed as Exhibit 10.15 to
Brigham’s Annual Report on Form 10-K for the year
ended December 31, 2003 and incorporated herein by reference |
| |
10.19 |
|
|
— |
|
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). |
| |
10.20 |
|
|
— |
|
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). |
| |
10.21 |
|
|
— |
|
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) |
| |
10.22 |
|
|
— |
|
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). |
| |
10.23 |
|
|
— |
|
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 10.36.1 to Brigham’s Registration Statement on
Form S-1 (Registration No. 333-22491), and
incorporated herein by reference). |
| |
|
|
|
|
|
|
| Number | |
|
|
|
Description |
| | |
|
|
|
|
| |
10.24 |
|
|
— |
|
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 (filed as Exhibit 10.31.2 to Brigham’s Annual
Report on Form 10-K for the year ended December 31,
1999 and incorporated by reference herein). |
| |
10.25 |
|
|
— |
|
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). |
| |
10.26 |
|
|
— |
|
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). |
| |
10.27 |
|
|
— |
|
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). |
| |
10.28 |
|
|
— |
|
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). |
| |
10.29 |
|
|
— |
|
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). |
| |
10.30 |
|
|
— |
|
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). |
| |
10.31 |
|
|
— |
|
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). |
| |
10.32 |
|
|
— |
|
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). |
| |
10.33 |
|
|
— |
|
Exchange Agreement, dated November 21, 2002 between Brigham
Exploration Company, Brigham Oil & Gas, L.P. and Shell
Capital Inc. (filed as Exhibit 10.47 to Brigham’s
Annual Report on Form 10-K for the year ended
December 31, 2002 and incorporated herein by reference). |
| |
10.34 |
|
|
— |
|
Omnibus Agreement dated November 21, 2002 between Brigham
Exploration Company, Brigham Oil & Gas, L.P. and
certain Credit Suisse First Boston entities (filed as
Exhibit 10.48 to Brigham’s Annual Report on
Form 10-K for the year ended December 31, 2002 and
incorporated herein by reference). |
| |
10.35 |
|
|
— |
|
Securities Purchase Agreement dated December 20, 2002
between Brigham Exploration Company and certain Credit Suisse
First Boston Entities (filed as Exhibit 10.49 to
Brigham’s Annual Report on Form 10-K for the year
ended December 31, 2002 and incorporated herein by
reference). |
| |
10.36 |
|
|
— |
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Registration Rights Agreement dated December 20, 2002
between Brigham Exploration Company and Shell Capital Inc.
(filed as Exhibit 10.50 to Brigham’s Annual Report on
Form 10-K for the year ended December 31, 2002 and
incorporated herein by reference). |
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| Number | |
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Description |
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10.37 |
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— |
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Second Amendment to Registration Rights Agreement dated
December 21, 2002 between Brigham Exploration Company and
Credit Suisse First Boston Entities (filed as Exhibit 10.51
to Brigham’s Annual Report on Form 10-K for the year
ended December 31, 2002 and incorporated herein by
reference). |
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10.38 |
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— |
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Third Amendment to Registration Rights Agreement May 24,
2004 between Brigham Exploration Company and Credit Suisse First
Boston Entities (filed as Exhibit 99.1 to Brigham’s
Current Report on Form 8-K (filed July 20, 2004), and
incorporated herein by reference). |
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10.39 |
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— |
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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 (filed as Exhibit 10.52 to
Brigham’s Annual Report on Form 10-K for the year
ended December 31, 2002 and incorporated herein by
reference). |
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10.40 |
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— |
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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. (filed as
Exhibit 10.53 to Brigham’s Annual Report on
Form 10-K for the year ended December 31, 2002 and
incorporated herein by reference). |
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10.41† |
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— |
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Third Amended and Restated Credit Agreement, dated
January 21, 2005 between Brigham Oil & Gas, L.P.,
Société Générale, Societe Generale, The
Royal Bank of Scotland plc and Bank of America, N.A. |
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10.42 |
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— |
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Amended and Restated Subordinated Credit Agreement, dated
March 21, 2003 between Brigham Oil & Gas, L.P.,
and The Royal Bank of Scotland plc (filed as Exhibit 10.54
to Brigham’s Annual Report on Form 10-K for the year
ended December 31, 2002 and incorporated herein by
reference). |
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10.43 |
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— |
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First Amendment to Amended and Restated Subordinated Credit
Agreement dated December 9, 2003 between Brigham
Oil & Gas, L.P., and The Royal Bank of Scotland plc
(filed as Exhibit 10.38 to Brigham’s Annual Report on
Form 10-K for the year ended December 31, 2002 and
incorporated herein by reference). |
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10.44 |
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— |
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Second Amendment to Amended and Restated Subordinated Credit
Agreement dated May 4, 2004 between Brigham Oil &
Gas, L.P., and The Royal Bank of Scotland plc (filed as
Exhibit 99.3 to Brigham’s Current Report on
Form 8-K (filed July 20, 2004), and incorporated
herein by reference). |
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10.45† |
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— |
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Second Amended and Restated Subordinated Credit Agreement dated
January 21, 2005 between Brigham Oil & Gas, L.P.,
and The Royal Bank of Scotland plc. |
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21† |
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Subsidiaries of the Registrant. |
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23.1† |
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— |
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Consent of PricewaterhouseCoopers LLP, Independent Registered
Public Accounting Firm. |
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23.2† |
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— |
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Consent of Cawley Gillespie & Associates, Inc. |
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31.1† |
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— |
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Certification of Chief Executive Officer pursuant to Sec. 302 of
the Sarbanes-Oxley Act of 2002 |
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31.2† |
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— |
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Certification of Chief Financial Officer pursuant to Sec. 302 of
the Sarbanes-Oxley Act of 2002 |
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32.1† |
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— |
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Certification of Chief Executive Officer pursuant to
18 U.S.C. SECTION 1350 |
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32.2† |
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— |
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Certification of Chief Financial Officer pursuant to
18 U.S.C. SECTION 1350 |
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| * |
Management contract or compensatory plan. |