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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the fiscal year ended December 31, 2004 | ||
or | ||
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission file number: 000-22433
Brigham Exploration Company
(Exact name of Registrant as Specified in its Charter)
Delaware | 75-2692967 | |
(State or other jurisdiction of incorporation or organization) | (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:
Title of Each Class | Name of Each Exchange on Which Registered | |
None | None |
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $.01 par value
(Title of Class)
Indicate by check mark whether the Registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 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
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BRIGHAM EXPLORATION COMPANY
2004 ANNUAL REPORT ON FORM 10-K
PART I
Item 1. | Business |
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:
• | 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. |
Further, we believe our focus on these five proven onshore trends within our three core provinces provides us with important drilling investment diversification. Since 1999, our drilling success in these trends has resulted in six significant field discoveries and a multi-year inventory of development drilling locations. We plan to focus a majority of our near term capital expenditures in these trends, where we believe our accumulated data and knowledge base provide a substantial competitive advantage. |
• | Internally Generate Inventory of High Quality Exploratory Prospects. We utilize 3-D seismic and other advanced technologies, including computer-aided exploration, to generate and maintain a large multi-year inventory of high quality exploratory prospects. Our highly skilled staff of 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. | |
• | 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. | |
• | 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. | ||
• | 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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Item 2. | Properties |
Our exploration and development activities are focused primarily in the onshore Texas Gulf Coast, the Anadarko Basin of northwest Oklahoma and the Texas Panhandle, and West Texas. We focus our activity in provinces where we believe 3-D seismic technology can be effectively used to maximize our return on capital invested by reducing drilling risk and enhancing our ability to cost-effectively grow reserves and production volumes.
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.
Onshore | ||||||||||||||||
Texas | Anadarko | West Texas | ||||||||||||||
Gulf Coast | Basin | & Other | Total | |||||||||||||
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
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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
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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
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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.
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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.
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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.”
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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.
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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.
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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 | |||||||
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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 |
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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
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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” Brighamhas served as our Chief Executive Officer, President and Chairman of the Board since we were founded in 1990. From 1984 to 1990, Mr. Brigham served as an exploration geophysicist with Rosewood Resources, an independent oil and gas exploration and production company. Mr. Brigham began his career in Houston as a seismic data processing geophysicist for Western Geophysical, Inc. a provider of 3-D seismic services, after earning his B.S. in Geophysics from the University of Texas 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. Brighamjoined us in 1992 and has served as a Director since May 2003 and as Executive Vice President — Land and Administration since June 2002. Mr. Brigham served as Senior Vice President — Land and Administration from March 2001 to June 2002, Vice President — Land and Administration from February 1998 to March 2001, as Vice President — Land and Legal from 1994 until February 1998 and as Corporate Secretary from February 1998 to September 2002. From 1987 to 1992, Mr. Brigham was an oil and gas attorney with Worsham, Forsythe, Sampels & Wooldridge. Before attending law school, Mr. Brigham was a landman for Wagner & Brown Oil and Gas Producers, an independent oil and gas exploration and production company. Mr. Brigham holds a B.B.A. in Petroleum
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Land Management from the University of Texas and a J.D. from Texas Tech School of Law. Mr. Brigham is the brother of Ben M. Brigham, Chief Executive Officer, President and Chairman of the Board.
A. Lance Langfordjoined us in 1995 as Manager of Operations and served as Vice President — Operations from January 1997 to March 2001, served as Senior Vice President — Operations from March 2001 to September 2003 and has served as Executive Vice President — Operations since September 2003. From 1987 to 1995, Mr. Langford served in various engineering capacities with Meridian Oil Inc., handling a variety of reservoir, production and drilling responsibilities. Mr. Langford holds a B.S. in Petroleum Engineering from Texas Tech University.
Jeffery E. Larsonjoined us in 1997 and was Vice President — Exploration from August 1999 to March 2001, Senior Vice President — Exploration from March 2001 to September 2003 and has served as Executive Vice President — Exploration since September 2003. Prior to joining us, Mr. Larson was an explorationist in the Offshore Department of Burlington Resources, a large independent exploration company, where he was responsible for generating exploration and development drilling opportunities. Mr. Larson worked at Burlington from 1990 to 1997 in various roles of responsibility. Prior to Burlington, Mr. Larson spent five years at Exxon as a Production Geologist and Research Scientist. He has a B.S. in Earth Science from St. Cloud State University in Minnesota and a M.S. in Geology from the University of Montana.
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.
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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,
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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
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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.
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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 |
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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. |
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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.
Oil and Gas Reserves |
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
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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.
Property and Equipment |
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
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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.
Income Taxes |
Deferred tax assets are recognized for temporary differences in financial statement and tax basis amounts that will result in deductible amounts and carry-forwards in future years. Deferred tax liabilities are recognized for temporary differences that will result in taxable amounts in future years. Deferred tax assets and liabilities are measured using enacted tax law and tax rate(s) for the year in which we expect the temporary differences to be deducted or settled. The effect of a change in tax law or rates on the valuation of deferred tax assets and liabilities is recognized in income in the period of enactment. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.
Estimating the amount of the valuation allowance is dependent on estimates of future taxable income, alternative minimum tax income, and changes in stockholder ownership that would trigger limits on use of net operating losses under Internal Revenue Code Section 382.
We have a significant deferred tax asset associated with net operating loss carryforwards (NOLs). It is more likely than not that we 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.”
Revenue Recognition |
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
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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.
Use of Estimates |
The preparation of financial statements in accordance with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect reported assets, liabilities, revenues, expenses, and some narrative disclosures. Hydrocarbon reserves, future development costs, and certain hydrocarbon production expense and revenue estimates are the most critical to our financial statements.
New Accounting Pronouncements |
In 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
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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 |
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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 Amortizationis 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 Expenseis the systematic, monthly accretion of future abandonment costs of tangible assets such as wells, service assets, pipelines, and other facilities. | |
• | General and Administrativeis 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.
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Capital Expenditures |
The timing of most of our capital expenditures is discretionary because we have no material long-term capital expenditure commitments. Consequently, we have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. Our capital 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
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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.”
Contractual Obligations |
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. |
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• 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. |
Senior Credit Facility |
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
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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
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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.
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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.”
Senior Credit Facility |
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.
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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 |
Production volumes |
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
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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. |
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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
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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 | ||||
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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 | |||||||||||
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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.
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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
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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. |
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• | 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 | ) | ||||||||||
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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.”
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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. |
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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 |
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.
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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.
Senior Credit Facility |
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
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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.”
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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
Derivative Instruments |
Our results of operations and operating cash flow are impacted by changes in market prices for oil and gas. We believe the use of derivative instruments, although not free of risk, allows us to reduce our exposure to oil and natural gas sales price fluctuations and thereby achieve a more predictable cash flow. While the use of derivative instruments limits the downside risk of adverse price movements, their use may also limit future revenues from favorable price movements. Moreover, our 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.
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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
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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.
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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.
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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.
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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
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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
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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; |
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• | the prices of oil and natural gas; | |
• | announcements by us and our competitors; | |
• | our liquidity; | |
• | our ability to raise additional funds; and | |
• | other events. |
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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.
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Item 7A. | Quantitative and Qualitative Disclosures About Market Risk |
Management Opinion Concerning Derivative Instruments
We use derivative instruments to manage exposure to commodity prices and interest rate risks. Our objectives for holding derivatives are to achieve a consistent level of cash flow to support a portion of our planned capital spending. Our use of derivative instruments for hedging activities could materially affect our results of operations in particular quarterly or annual periods since such instruments can limit our ability to benefit from favorable price movements. We do not enter into derivative instruments for trading purposes.
Fair Value of Derivative Contracts
The fair value of our derivative contracts is determined based on counterparties’ estimates and valuation models. We did not change our valuation methodology during the year ended December 31, 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.
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The gas derivative transactions are generally settled based upon the average of the reporting settlement prices on the NYMEX for the last three trading days of a particular contract month. The oil derivative transactions are generally settled based on the average reporting settlement prices on the NYMEX for each trading day of a particular calendar month.
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.
Cash Flow Hedges |
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.
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The following table reflects our open commodity derivative contracts at March 31, 2005, the associated volumes and the corresponding weighted average NYMEX reference price.
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.
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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.
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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 inInternal Control — Integrated Frameworkissued 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 inInternal Control — Integrated Frameworkissued 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.
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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.
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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
3. | Exhibits: |
The exhibits listed in the accompanying Index to Exhibits are filed or incorporated by reference as part of the annual report.
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GLOSSARY OF OIL AND GAS TERMS
The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry and in this report. The definitions of proved developed reserves, proved reserves and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.
3-D seismic. The method by which a three dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, development and production.
All-Sources Finding Costs. The cost associated with acquiring and developing proved oil and natural gas reserves determined on an Mcfe basis by dividing total net capital expenditures, excluding proceeds from the sale of proved oil and gas reserves, associated with drilling and completing of wells, acquiring acreage and geological and geophysical work during the identified period, by the estimated proved reserve additions from exploration and development activities, acquisitions of proved reserves and revisions of previous estimates during the same time period.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to oil or other liquid hydrocarbons.
Bcfe. One billion cubic feet of natural gas equivalent. In reference to natural gas, natural gas equivalents are determined using the ratio of 6 Mcf of natural gas to 1 Bbl of oil, condensate or natural gas liquids.
Completion. The installation of permanent equipment for the production of oil or natural gas. Completion of the well does not necessarily mean the well will be profitable.
Completion Rate. The number of wells on which production casing has been run for a completion attempt as a percentage of the number of wells drilled.
Developed Acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.
Development Well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry Well. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion of an oil or gas well.
Exploratory Well. A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir.
Fault. A break in the rocks along which there has been movement of one side relative to the other side.
Fault Block. A body of rocks bounded by one or more faults.
Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which we have a working interest.
Lease Operating Expenses. The expenses, usually recurring, which pay for operating the wells and equipment on a producing lease.
MBbl. One thousand barrels of oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet of natural gas.
MMBbl. One million barrels of oil or other liquid hydrocarbons.
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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.
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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.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, hereunder duly authorized, as of March 31, 2005.
Brigham Exploration Company |
By: | /s/Ben M. Brigham |
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 | Chief Executive Officer, President and Chairman of the Board (Principal Executive Officer) | |||
/s/Eugene B. Shepherd, Jr. | Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer) | |||
/s/David T. Brigham | Executive Vice President — Land and Administration and Director | |||
/s/Harold D. Carter | Director | |||
/s/Stephen C. Hurley | Director | |||
/s/Stephen P. Reynolds | Director | |||
/s/Hobart A. Smith | Director | |||
/s/Steven A. Webster | Director | |||
/s/R. Graham Whaling | Director |
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BRIGHAM EXPLORATION COMPANY
INDEX TO FINANCIAL STATEMENTS
Page | ||||
Report of Independent Registered Public Accounting Firm | F-2 | |||
Consolidated Balance Sheets as of December 31, 2004 and 2003 | F-4 | |||
Consolidated Statements of Operations for the Years Ended December 31, 2004, 2003 and 2002 | F-5 | |||
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2004, 2003 and 2002 | F-6 | |||
Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002 | F-7 | |||
Notes to the Consolidated Financial Statements | F-8 | |||
Supplemental Oil and Gas Information (Unaudited) | F-36 | |||
Supplemental Quarterly Financial Information (Unaudited) | F-39 |
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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 inInternal Control — Integrated Frameworkissued 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,
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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 inInternal Control — Integrated Frameworkissued 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 inInternal Control — Integrated Frameworkissued by the COSO.
/s/ PricewaterhouseCoopers LLP
March 30, 2005
Houston, Texas
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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.
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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.
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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.
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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.
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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. | Organization and Nature of Operations |
Brigham Exploration Company is a Delaware corporation formed on February 25, 1997 for the purpose of exchanging its common stock for the common stock of Brigham, Inc. and the partnership interests of Brigham Oil & Gas, L.P. (the “Partnership”). Hereinafter, Brigham Exploration Company and the Partnership are collectively referred to as “Brigham.” Brigham, Inc. is a Nevada corporation whose only asset is its ownership interest in the Partnership. The Partnership was formed in May 1992 to explore and develop onshore domestic oil and natural gas properties using 3-D seismic imaging and other advanced technologies. Since its inception, the Partnership has focused its exploration and development of oil and natural gas properties primarily in the onshore Texas Gulf Coast, the Anadarko Basin and West Texas.
Summary of Significant Accounting Policies
Use of Estimates |
The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates relate to proved oil and natural gas reserve volumes and the future development costs as well as estimates relating to certain oil and natural gas revenues and expenses. Actual results may differ from those estimates.
Principles of Consolidation |
The accompanying financial statements include the accounts of Brigham and its wholly owned subsidiaries, and its proportionate share of assets, liabilities and income and expenses of the limited partnerships in which Brigham, or any of its subsidiaries has a participating interest. All significant intercompany accounts and transactions have been eliminated.
Cash and Cash Equivalents |
Brigham considers all highly liquid financial instruments with an original maturity of three months or less to be cash equivalents.
Property and Equipment |
Brigham uses the full cost method of accounting for oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including 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
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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.
Revenue Recognition |
Brigham recognizes crude oil revenues using the sales method of accounting. Under this method, Brigham recognizes revenues when oil is delivered and title transfers.
Brigham recognizes natural gas revenues using the entitlements method of accounting. Under this method, revenues are recognized based on Brigham’s entitled ownership percentage of sales of natural gas to purchasers. Gas imbalances occur when Brigham sells more or less than its entitled ownership percentage of total natural gas production. When Brigham receives less than its entitled share, a receivable is recorded. When Brigham receives more than its entitled share, a liability is recorded.
The following 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
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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 | ) | ||||
Stock Based Compensation |
Brigham accounts for employee stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees”. Accordingly, Brigham has adopted the disclosure-only provisions of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (SFAS 123).
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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Under SFAS 123, the fair value of each stock option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for grants during the years ended December 31, 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 | ) |
Income Taxes |
Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates of deferred tax assets and liabilities is recognized in income in the year of the enacted rate change. Deferred tax assets are reduced by a valuation allowance when, in the opinion of
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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 |
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.
Segment Information |
All of Brigham’s oil and natural gas properties and related operations are located onshore in the United States and management has determined that Brigham has one reportable segment.
Treasury Stock |
Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held.
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 | ) | ||||
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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.
New Pronouncements |
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
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Table of Contents
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).
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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,
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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 | |||||
Senior Credit Facility |
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
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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.
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BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
5. | Preferred Stock |
Series A Mandatorily Redeemable Preferred Stock |
The following table reflects the outstanding shares of Series A mandatorily redeemable preferred stock and the activity related thereto for the years ended December 31, 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.
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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.
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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
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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 | ) | $ | — | |||||||
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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 | ||||||||||
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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 | ||||||
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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 | ) | |||||||
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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
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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
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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.
Major Purchasers |
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
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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 |
Cash-flow hedges |
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 | — |
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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 |
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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.
Interest rate swap |
Periodically, Brigham may use interest rate swap contracts to adjust the proportion of its total debt that is subject to variable interest rates. Under such an interest rate swap contract, Brigham agrees to pay an amount equal to a specified fixed-rate of interest for a certain notional amount and receive in return an amount equal to a variable-rate. The notional amounts of the contract are not exchanged. No other cash payments are made unless the contract is terminated prior to maturity. Although no collateral is held or exchanged for the contract, the interest rate swap contract is entered into with a major financial institution in order to minimize Brigham’s counterparty credit risk. The interest rate swap contract is designated as cash flow hedges against changes in the amount of future cash flows associated with Brigham’s interest payments on variable-rate debt. The effect of this accounting on operating results is that interest expense on a portion of variable-rate debt being hedged is recorded based on fixed interest rates.
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.
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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
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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 | |||||||||||||
Restricted Stock |
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
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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.
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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.
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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.
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Table of Contents
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
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Table of Contents
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.
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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 | |||||||
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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 | ||||||||||
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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 | |||||||||||||||||
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Table of Contents
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). |
Table of Contents
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). |
Table of Contents
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 | — | 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). |
Table of Contents
Number | Description | |||||
10.37 | — | 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). | ||||
10.38 | — | 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). | ||||
10.39 | — | 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). | ||||
10.40 | — | 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). | ||||
10.41† | — | 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. | ||||
10.42 | — | 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). | ||||
10.43 | — | 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). | ||||
10.44 | — | 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). | ||||
10.45† | — | Second Amended and Restated Subordinated Credit Agreement dated January 21, 2005 between Brigham Oil & Gas, L.P., and The Royal Bank of Scotland plc. | ||||
21† | — | Subsidiaries of the Registrant. | ||||
23.1† | — | Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm. | ||||
23.2† | — | Consent of Cawley Gillespie & Associates, Inc. | ||||
31.1† | — | Certification of Chief Executive Officer pursuant to Sec. 302 of the Sarbanes-Oxley Act of 2002 | ||||
31.2† | — | Certification of Chief Financial Officer pursuant to Sec. 302 of the Sarbanes-Oxley Act of 2002 | ||||
32.1† | — | Certification of Chief Executive Officer pursuant to 18 U.S.C. SECTION 1350 | ||||
32.2† | — | Certification of Chief Financial Officer pursuant to 18 U.S.C. SECTION 1350 |
* | Management contract or compensatory plan. |
† | Filed herewith. |