MILLER EXPLORATION CO - 10-K Annual Report

Miller Exploration Company (“Miller” or the “Company”) is an independent oil and gas exploration and production company with exploration efforts concentrated primarily in the Mississippi Salt Basin of Central Mississippi. Miller emphasizes the use of 3-D seismic data analysis and imaging, as well as other emerging technologies, to explore for and develop oil and natural gas in its core exploration area. Miller is the successor to Miller Oil Corporation (“MOC”), an independent oil and natural gas exploration and production business first established in Michigan by members of the Miller family in 1925. References herein to the “Company” or “Miller” are to Miller Exploration Company, a Delaware corporation, and its subsidiaries and predecessors.

The Combination Transaction closed on February 9, 1998 in connection with the closing of the Company’s initial public offering of 5.5 million shares of Common Stock (the “Offering”). The Offering, including the sale of an additional 62,500 shares of Common Stock by the Company on March 9, 1998 pursuant to the exercise of the underwriters’ over-allotment option, resulted in net proceeds to the Company of approximately $40.4 million after expenses.

Miller incurred expenditures for exploration and development activity of $10.0 million with respect to the Company’s interest in 14 gross wells (5.5 net to the Company) for the year ended December 31, 2001 and $8.6 million with respect to the Company’s interest in 8 gross wells (1.8 net to the Company) for the year ended December 31, 2000. At December 31, 2001, the Company also had 3 gross wells (0.2 net to the Company) in the process of drilling and/or completing. The Company currently plans to drill 10 gross wells (3.2 net to the Company) in 2002. The Company anticipates 2002 capital expenditures for exploration and development activity in all of its areas of concentration will be approximately $3.0 million, net of savings associated with promoted and carried working interests in wells to be drilled in 2002.

The Company believes that the Mississippi Salt Basin, which extends from Southwestern Alabama across central Mississippi into Northeastern Louisiana, has a number of under-developed salt domes. A salt dome is a generally dome-shaped intrusion into sedimentary rock that has a mass of salt as its core. The impermeable nature of the salt dome structure may act as a mechanism to trap hydrocarbons migrating through surrounding rock formations. These geologic structures were formed by the upward thrusting of subsurface salt accumulations towards the surface. These structures generally are found in groups in geologic basins that provide the necessary conditions for their formation. Salt domes are typically subsurface structures that are easily identified with seismic surveys, but occasionally are visible as surface expressions. The salt domes of the Mississippi Salt Basin were formed in the Cretaceous period. These salt domes range in diameter from ½ mile to three miles and vertically extend from 2,000 feet to nearly 20,000 feet in depth. Salt domes similar to those of the Mississippi Salt Basin are a significant cause for major oil and gas accumulations in the Texas and Louisiana Gulf Coast, Northern Louisiana, East Texas and the offshore Gulf of Mexico. This basin has produced substantial amounts of oil and natural gas and continues to be a very active exploration region. Oil and natural gas discovered in the Mississippi Salt Basin have been produced from reservoirs with various stratigraphic and structural characteristics, and may be found in multiple horizons from approximately 3,500 feet to 19,000 feet in depth. Oil and natural gas reserves around salt domes have been encountered in the Eutaw, Lower Tuscaloosa, Washita-

The Company believes that the key to exploiting salt dome prospects effectively is the accurate delineation of a salt dome’s flanks, with the recognition of fault patterns and the location of fault blocks with large reserve potential. While reinterpreted 2-D seismic data provided the Company’s explorationists with better imaging of a salt dome’s subsurface structures, it proved to have limitations in defining the exact locations of the flanks of a salt dome. In 1998, the Company acquired approximately 400 square miles of 3-D seismic data in the Mississippi Salt Basin. The Company believes that wells drilled on the 3-D data demonstrate that the 3-D seismic more effectively images the edge of the salt dome, identifying areas that had not been seen on the 2-D seismic, in addition to providing better definition of the size and location of future drilling targets. The Company has continued to use technologically advanced seismic processing methods including prestack depth migration on the 3-D data.

The Company owns an interest in 19 producing wells in the Mississippi Salt Basin that had an aggregate average production rate as of December 31, 2001 of 40.0 million cubic feet of natural gas equivalent per day (“MMcfe/d”) gross (11.8 MMcfe/d net to the Company) at depths ranging from 10,800 to 17,900 feet. The Company has 5 gross wells (1.0 net to the Company) budgeted in 2002 for the Mississippi Salt Basin with a capital expenditure budget of $2.8 million, including $0.5 million for land and seismic costs. All 5 of the Mississippi Salt Basin wells budgeted for 2002 will be based on 3-D seismic data, 2 of which will be development wells in the Pine Grove Field of the Mississippi Salt Basin.

The Company entered into an Exploration and Development Agreement (the “EDA”) with K2 Energy Corporation on June 17, 1998 to explore and develop approximately 150,000 gross leasehold acres on the Blackfeet Indian Reservation (the “Reservation”) located in Glacier County, Montana. The EDA provides that Miller and K2 are equal partners in the K2/Blackfeet Agreement (the “K2 Agreement”) executed between K2 and the Blackfeet Tribe (the “Tribe”) on March 9, 1998. Terms of the Agreement call for Miller/K2 to drill three gross wells (1.5 net to the Company) and pay $0.6 million ($0.3 million net to the Company) to the Tribe by May 1, 1999 for which 30,000 gross acres (15,000 net to the Company) will be earned from the Tribe. Three gross additional wells (1.5 net to the Company) must be drilled and $0.6 million paid ($0.3 million net to the Company) to the Tribe each subsequent year for four years totaling 15 gross wells (7.5 net to the Company) and $3.0 million ($1.5 million net to the Company) in payments to the Tribe for which 150,000 gross acres (75,000 net to the Company) will be earned. The Tribe will grant leases with a primary term of eight years and can be held by production for 45 years and provides for a maximum combined royalty and production tax burden of 35%. In May 2000, the Company filed a lawsuit against K2 to secure its rights to develop Tribal acreage covered by the K2 Agreement. See “Item 3 — Legal Proceedings” for a discussion of this litigation.

The Company entered into a separate Indian Mineral Development Act (“IMDA”) Agreement with the Tribe covering 100,000 Tribal acres that was approved February 26, 1999 (the “Miller Agreement”). Terms of the Miller Agreement call for the Company to pay $1.0 million to the Tribe upon approval and approximately $0.5 million on the second and third anniversary of the February 26, 1999 Agreement. The Company is also obligated to drill a minimum of two wells each year with a total commitment of 10 wells over a five-year period. In addition to the standard force majeure language, Miller negotiated the ability for a one-year extension of the drilling commitment to which the Tribe agreed it would not unreasonably withhold its consent. The terms of the extension were payment of an additional $2 per acre up to a maximum of $200,000 prorated for the number of months the extension was granted. The specific provisions of the Miller Agreement provide that the Company will not ask for an unreasonable amount of time nor will the Tribe unreasonably withhold its consent. The Company will earn the right to lease 20,000 acres with each set of 2 wells drilled, regardless of the outcome of the wells. Separate oil and gas leases covering 640-acre blocks will be issued with a $2 per acre rental and an

eight-year term. Pursuant to the terms of the EDA executed on June 17, 1998, K2 was offered their exclusive right to purchase 50% of the Company’s interest in the Miller Agreement for cost plus 20% on June 7, 1999. K2 conditionally accepted this offer and, to date, has not paid for its proportionate share of costs for said lands. On May 1, 2000, the Company gave notice to the Blackfeet Tribal Business Council demanding arbitration of all disputes as provided for under the Miller Agreement dated February 19, 1999, and pursuant to the K2 Agreement dated May 30, 1997. See “Legal Proceedings” for a discussion of this arbitration.

During 2001 and 2000, the Company acquired 12,386 gross non-Tribal acres (10,451 net to the Company) on the Reservation. The Company plans on drilling 2 gross (1.7 net to the Company) wells on these non-Tribal lands in 2002. The northern boundary of the Reservation is located approximately 25 miles south of the Waterton, Lookout Butte and Pincher Creek Fields (Alberta, Canada), which have produced in excess of 3.8 trillion cubic feet of natural gas (“Tcf”), 0.3 Tcf and 0.5 Tcf, respectively. The eastern boundary of the Reservation is outlined by the Cut Bank Oil Field (Glacier County, Montana), which has produced in excess of 175 million barrels of oil (“MMBbl”) and 309 Bcf of natural gas.

Since March 1993, the Company has entered into a series of joint venture exploration agreements and farm-out agreements with Amerada Hess Corporation (“AHC”), Liberty Energy Corporation, Bonray, Inc., Key Production Company Inc. (“Key”), Remington Oil & Gas Corp. (“Remington”) and Eagle Investments, Inc. (“Eagle”). These agreements govern the rights and obligations of the Company and the other working-interest owners with respect to lease acquisition, seismic surveys, drilling and development of specified geographic areas of mutual interest (AMI’s) over and around several salt domes and related salt structures in Southern Mississippi within the Mississippi Salt Basin The joint venture exploration agreements began to expire January 1, 2000, except with respect to AMI’s in which the Company and its partners have established production and where joint operating agreements have been executed. In the case where joint operating agreements have been executed, the term extends as long as any lease within that AMI remains in effect.

	Year Ended December 31,
	2001		2000		1999
Production:
Crude oil and condensate (MBbls)		159.6		205.3		255.9
Natural gas (MMcf)		3,473.2		5,762.0		7,593.8
Natural gas equivalent (MMcfe)		4,430.9		6,993.8		9,129.2
Average sales prices:
Crude oil and condensate ($ per Bbl)	$	21.90	$	25.82	$	13.54
Natural gas ($ per Mcf)		4.12		3.60		2.27
Natural gas equivalent ($ per Mcfe)		4.02		3.72		2.27
Average costs ($ per Mcfe):
Lease operating expenses and production taxes	$	0.66	$	0.43	$	0.19
Depreciation, depletion and amortization		3.03		2.49		1.76
General and administrative		0.42		0.30		0.34

Most of the Company’s oil and natural gas production is sold under price sensitive or spot market contracts. The revenues generated by the Company’s operations are highly dependent upon the prices of and demand for oil and natural gas. The price received by the Company for its oil and natural gas production depends on numerous factors beyond the Company’s control, including seasonality, the condition of the United States economy, foreign imports, political conditions in other oil-producing and natural gas-producing countries, the actions of the Organization of Petroleum Exporting Countries and domestic government regulation, legislation and policies. Crude oil and natural gas commodity prices have been volatile and unpredictable during the past three years. The wide commodity price fluctuations have had a significant impact on the Company’s results of operations, cash flow and liquidity. Although the Company currently is not experiencing any significant involuntary curtailment of its oil or natural gas production, market, economic and regulatory factors in the future may materially affect the Company’s ability to sell its oil or natural gas production. For the year ended December 31, 2001, sales to the Company’s three largest customers were approximately 60%, 16%, and 12%, respectively, of the Company’s oil and natural gas revenues. Due to the availability of other markets and pipeline connections, the Company does not believe that the loss of any single oil or natural gas customer would have a material adverse effect on the Company’s results of operations or financial condition.

The oil and gas industry is highly competitive in all of its phases. The Company encounters competition from other oil and natural gas companies in all areas of its operations, including the acquisition of seismic options and lease options on properties. The Company’s competitors include major integrated oil and natural gas companies and numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of the Company’s competitors are large, well established companies with substantially larger operating staffs and greater capital resources than the Company’s and which, in many instances, have been engaged in the exploration and production business for a much longer time than the Company. Such companies may be able to pay more for seismic and lease options on oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than the Company’s financial or human resources permit. The Company’s ability to explore for oil and natural gas prospects, to acquire additional properties and to discover reserves in the future will depend upon its ability to conduct its operations, to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

The Company believes it has satisfactory title to all of its producing properties in accordance with standards generally accepted in the oil and gas industry. As is customary in the industry in the case of undeveloped properties, little investigation of record title is made at the time of acquisition (other than a preliminary review of local records). Investigations, including a title opinion of legal counsel, generally are made before commencement of drilling operations. To the extent title opinions or other investigations reflect title defects, the Company, rather than the seller of undeveloped property, typically is responsible to cure any such title defects at the Company’s expense. If the Company were unable to remedy or cure title defect of a nature such that it would not be prudent to commence drilling operations on the property, the Company could suffer a loss of its entire investment in such property. The Company’s properties are subject to customary royalty, overriding royalty, carried, net profits, working and other similar interests, liens incident to operating agreements, liens for current taxes and other burdens. In addition, the Company’s credit facility is secured by all oil and natural gas interests and other properties of the Company.

The State of Mississippi currently has a production tax abatement program that exempts certain oil and natural gas production from state production taxes. The exemption as it relates to the Company applies to, among other things, discovery wells, exploratory wells, and wells developed as a result of 3-D seismic surveys. The exemption is phased out if the average monthly sales price for oil and gas exceeds $25.00 per Bbl and $3.50 per Mcf, respectively. The applicable production is exempt for up to five years and the exemption expires June 30, 2003. In April 1999, the State of Mississippi enacted a bill that reduced the production tax exemption to 3% of the value of oil and/or gas for five years for exploratory wells or wells for which 3-D seismic was utilized (three years for a development well) for wells drilled on or after July 1, 1999, provided that the average monthly sales price of oil or gas does not exceed $20 per barrel or $2.50 per Mcf of gas, respectively. The reduced rate will be repealed on July 1, 2003. During 2001 and 2000, the production tax exemption has phased in and out, due to the volatility of the average monthly rates as they relate to the pre-established price limits stipulated in the state statutes. As of December 31, 2001, all applicable production tax exemptions are in effect.

The Company’s oil and natural gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal, state and local agencies. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases the Company’s cost of doing business and affects its profitability. Although the Company believes it is in substantial compliance with all applicable laws and regulations, the Company is unable to predict the future cost or impact of complying with such laws because those laws and regulations frequently are amended or reinterpreted.

The states in which the Company operates 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. In addition, state laws generally prohibit the venting or flaring of natural gas, regulate the disposal of fluids used in connection with operations and impose certain requirements regarding the ratability of production.

Regulatory Commission (“FERC”) regulates the transportation and sale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. In the past, the federal government has regulated the prices at which oil and natural gas can be sold. While sales by producers of natural gas and all sales of oil and natural gas liquids currently can be made at uncontrolled market prices, Congress could reenact price controls in the future.

In recent years, FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like FERC Order 636, issued in April 1992, and its progeny, the interstate natural gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No. 636 require that interstate pipelines provide transportation separate or “unbundled” from their sales services, and require that pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas supplies. In many instances, the result of Order No. 636 and related initiatives has been to substantially reduce or eliminate the interstate pipelines’ traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. The courts have largely affirmed the significant features of Order No. 636 and numerous related orders pertaining to the individual pipelines, although certain appeals remain pending and the FERC continues to review and modify its open access regulations.

In particular, the FERC has been conducting a broad review of its transportation regulations, including how they operate in conjunction with state proposals for retail gas market restructuring, whether to eliminate cost-of-service rates for short-term transportation, whether to allocate all short-term capacity on the basis of competitive auctions, and whether changes to long-term transportation policies may also be appropriate to avoid a market bias toward short-term contracts. In February 2000, the FERC issued Order No. 637 amending certain regulations governing interstate natural gas pipeline companies in response to the development of more competitive markets for natural gas and natural gas transportation. The goal of Order No. 637 is to “fine tune” the open access regulation implemented by Order No. 636 to accommodate subsequent changes in the market. Key provisions of Order No. 637 include (1) waiving the price ceiling for short-term capacity release transactions until September 30, 2002, subject to review and possible extension; (2) permitting pipelines to charge different maximum cost-based rates for peak and off peak times, and for contracts with different term lengths; (3) encouraging auctions for pipeline capacity; (4) restricting the ability of pipelines to impose penalties for imbalances, overruns, and non-compliance with pipeline operational flow orders; and (5) requiring pipelines to implement imbalance management services. Most major aspects of Order No. 637 have been challenged on appeal. The Company cannot predict what action the FERC will take on these matters in the future, or whether FERC’s actions will survive judicial review.

Similarly, the Texas Railroad Commission recently has changed its regulations governing transportation and gathering services provided by intrastate pipelines and gatherers to prohibit undue discrimination in favor of affiliates. While the changes being implemented and considered by these federal and state regulators would affect the Company only indirectly, they are intended to further enhance competition in natural gas markets. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC, state commissions and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC and Congress will continue.

The price the Company receives from the sale of oil and natural gas liquids is affected by the cost of transporting products to markets. Effective January 1, 1995, FERC implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index such rates to inflation, subject to certain conditions and limitations. The Company is not able to predict with certainty the effect, if any, of these regulations on its operations. However, the regulations may increase transportation costs or reduce well head prices for oil and natural gas liquids.

The Company’s operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences; restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities; limit or prohibit construction, drilling and other activities on certain lands lying within wilderness, wetlands and other protected areas; require remedial measures to mitigate pollution from former operations such as plugging abandoned wells; and impose substantial liabilities for pollution resulting from the Company’s operations. The permits required for various of the Company’s operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations, and violators are subject to civil and criminal penalties or injunction. Management believes that the Company is in substantial compliance with current applicable environmental laws and regulations, and that the Company has no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on the Company, as well as the oil and gas industry in general and thus the Company is unable to predict the ultimate costs and effects of such continued compliance in the future.

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) and comparable state statutes impose strict, joint and several liability on certain classes of persons who are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a disposal site or sites where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances released at the site. Under CERCLA such persons or companies may be liable for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for the neighboring land owners and other third parties to file claims for personal injury, property damage and recovery of response costs 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 civil and criminal penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting the Company’s operations impose clean-up liability relating to petroleum and petroleum-related products. In addition, although RCRA classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements.

The Company has acquired leasehold interests in several properties that for many years have produced oil and natural gas. Although the Company believes that the previous owners of these interests used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed or released on or under the properties. In addition, several of the Company’s properties are operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes is not under the Company’s control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Notwithstanding the Company’s lack of control over properties operated by others, the failure of the operator to comply with applicable environmental regulations may, in certain circumstances, adversely impact the Company.

Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as the Company, to prepare and implement spill prevention, control countermeasure and response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990, as amended (“OPA”), contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States.

For onshore facilities that may affect waters of the United States, OPA requires an operator to demonstrate $10.0 million in financial responsibility, and for offshore facilities the financial responsibility requirement is at least $35.0 million. Regulations currently are being developed under federal and state laws concerning oil pollution prevention and other matters that may impose additional regulatory burdens on the Company. In addition, the federal Clean Water Act and analogous state laws require permits to be obtained to authorize discharge into surface waters or to construct facilities in wetland areas. With respect to certain of its operations, the Company is required to maintain such permits or meet general permit requirements. The Environmental Protection Agency (“EPA”) has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits, participate in a group or seek coverage under an EPA general permit. The Company believes that it will be able to obtain, or be included under, such permits where necessary, and to make minor modifications to existing facilities and operations that would not have a material effect on the Company.

As of March 20, 2002, the Company had 23 full-time employees, including two geologists, a geophysicist and two engineers. None of the Company’s employees are represented by any labor union. The Company believes its relations with its employees are good. To optimize prospect generation and development, the Company uses the services of independent consultants and contractors to perform various professional services, particularly in the area of seismic data mapping, acquisition of leases and lease options, construction, design, well-site surveillance, permitting and environmental assessment. Field and on-site productions operation services, such as pumping, maintenance, dispatching, inspection and testing, generally are provided by independent contractors. The Company believes that this use of third-party service providers enhances its ability to contain general and administrative expenses.

The Company’s revenues, operating results and future rate of growth are substantially dependent upon the success of its exploratory drilling program. Exploratory drilling involves numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, adverse weather conditions, compliance with governmental requirements and shortages or delays in the availability of drilling rigs and the delivery of equipment. Despite the use of 2-D and 3-D seismic data and other advanced technologies, exploratory drilling remains a speculative activity. Even when fully utilized and properly interpreted, 2-D and 3-D seismic data and other advanced technologies only assist geoscientists in identifying subsurface structures and do not enable the interpreter to know whether hydrocarbons are in fact present in those structures. In addition, the use of 2-D and 3-D seismic data and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, and the Company could incur losses as a result of such expenditures. The Company’s future drilling activities may not be successful. There can be no assurance that the Company’s overall drilling success rate or its drilling success rate for activity within a particular region will not decline. Unsuccessful drilling activities could have a material adverse effect on the Company’s business, results of operations and financial condition.

The Company may not have any option or lease rights in potential drilling locations it identifies. Although the Company has identified numerous potential drilling locations, there can be no assurance that they will ever be leased or drilled or that oil or natural gas will be produced from these or any other potential drilling locations. In addition, drilling locations initially may be identified through a number of methods, some of which do not include interpretation of 3-D or other seismic data. Actual drilling results are likely to vary from such statistical results, and such variance may be material. Similarly, the Company’s drilling schedule may vary from its capital budget, and there is increased risk of such variances from the 2002 capital budget because of future uncertainties,

The Company’s operations are subject to hazards and risks inherent in drilling for and producing and transporting oil and natural gas, such as fires, natural disasters, explosions, encountering formations with abnormal pressures, blowouts, craterings, pipeline ruptures and spills, uncontrollable flows of oil, natural gas or well fluids, any of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to properties of the Company and others. The Company maintains insurance against some but not all of the risks described above. In particular, the insurance maintained by the Company does not cover claims relating to failure of title to oil and natural gas leases, trespass during 2-D and 3-D survey acquisition or surface change attributable to seismic operations and, except in limited circumstances, losses due to business interruption. The Company may elect to self-insure if management believes that the cost of insurance, although available, is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The Company occasionally participates in wells on a non-operated basis, which may limit the Company’s ability to control the risks associated with oil and natural gas operations. The occurrence of an event that is not covered, or not fully covered, by insurance could have a material adverse effect on the Company’s business, financial condition and results of operations.

The Company’s revenues, operating results and future rate of growth are substantially dependent upon the prevailing prices of, and demand for, oil and natural gas. Historically, the markets for oil and natural gas have been volatile and are likely to continue to be volatile in the future. Prices for oil and natural gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond the control of the Company. These factors include global 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. It is impossible to predict future oil and natural gas price movements with certainty. A continuation of the significantly lower oil and gas prices experienced by the Company in the fourth quarter of 2001, as compared to historical averages, would likely have a material adverse effect on the Company’s financial condition, liquidity, ability to finance planned capital expenditures and results of operations. Lower oil and natural gas prices also may reduce the amount of oil and natural gas that the Company can produce economically.

The Company periodically reviews the carry value of its oil and natural gas properties under the full cost accounting rules of the Securities and Exchange Commission (“SEC”). Under these rules, capitalized costs of proved oil and natural gas properties may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%, and the lower of cost or market value of unproved properties. Application of the “ceiling” test generally requires pricing future revenue at the unescalated prices in effect as of the end of each fiscal quarter and requires a writedown for accounting purposes if the ceiling is exceeded, even if prices were depressed for only a short period of time. The Company may be required to writedown the carrying value of its oil and natural gas properties when oil and natural gas prices are depressed or unusually volatile. If a writedown is required, it would result in a charge to earnings, but would not impact cash flow from operating activities. Once incurred, a writedown of oil and natural gas properties is not reversible at a later date (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations”).

and management, project and prospect generation, land acquisition, drilling and other services. If the Company increases the number of projects it is evaluating or in which it is participating, there will be additional demands on the Company’s financial, technical, operational and administrative resources and continued reliance by the Company on project partners and independent contractors, and these strains on resources, additional demands and continued reliance may negatively affect the Company. The Company’s ability to grow will depend upon a number of factors, including its ability to obtain leases or options on properties, its ability to acquire additional 3-D seismic data, its ability to identify and acquire new exploratory sites, its ability to develop existing sites, its ability to continue to retain and attract skilled personnel, its ability to maintain or enter into new relationships with project partners and independent contractors, the results of its drilling program, hydrocarbon prices, access to capital and other factors. There can be no assurance that the Company will be successful in achieving growth or any other aspect of its business strategy.

Except to the extent that the Company conducts successful exploration and development activities or acquires properties containing proved reserves, or both, the proved reserves of the Company will decline as reserves are produced. The Company’s future oil and natural gas production is highly dependent upon its ability to economically find, develop or acquire reserves in commercial quantities. The business of exploring for or developing reserves is capital intensive. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, the Company’s ability to make the necessary capital investment to maintain or expand its asset base of oil and natural gas reserves would be impaired. The Company occasionally participates in wells as non-operator. The failure of an operator of the Company’s wells to adequately perform operations, or an operator’s breach of the applicable agreements, could adversely impact the Company. In addition, there can be no assurance that the Company’s future exploration and development activities will result in additional proved reserves or that the Company will be able to drill productive wells at acceptable costs. Furthermore, although the Company’s revenues could increase if prevailing prices for oil and natural gas increase significantly, the Company’s finding and development costs also could increase.

The marketability of the Company’s natural gas production depends in part upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. The Company delivers natural gas through gas gathering systems and gas pipelines that it does not own. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand and general economic conditions all could adversely affect the Company’s ability to produce and market its oil and natural gas. Any dramatic change in market factors could have a material adverse effect on the Company’s business, financial condition and results of operations.

The Company has assembled a team of geologists, geophysicists and engineers, some of whom are non-employee consultants and independent contractors, having considerable experience in oil and natural gas exploration and production, including applying 2-D and 3-D imaging technology. The Company is dependent upon the knowledge, skills and experience of these experts to provide 2-D and 3-D imaging and to assist the Company in reducing the risks associated with its participation in oil and natural gas exploration projects. In addition, the success of the Company’s business also depends to a significant extent upon the abilities and continued efforts of its management. The Company does not maintain key-man life insurance with respect to any of its employees. The loss of services of key management personnel or the Company’s technical experts and consultants, or the inability to attract additional qualified personnel, experts or consultants, could have a material adverse effect on the Company’s business, financial condition, results of operations, development efforts and ability to grow. There can be no assurance that the Company will be successful in attracting and/or retaining its key management personnel or technical experts or consultants.

technologies, the Company may be placed at a competitive disadvantage, and competitive pressures may force the Company to implement such new technologies at substantial costs. In addition, other oil and gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before the Company. There can be no assurance that the Company will be able to respond to such competitive pressures and implement such technologies on a timely basis or at an acceptable cost. One or more of the technologies currently utilized by the Company or implemented in the future may become obsolete. In such cases, the Company’s business, financial condition and results of operations could be materially adversely affected. If the Company is unable to utilize the most advanced commercially available technology, the Company’s business, financial condition and results of operations could be materially and adversely affected.

The Company makes and will continue to make capital expenditures in connection with its exploration and development projects. The Company intends to finance these capital expenditures with cash flow from operations as currently projected. Additional financing may be required in the future to fund the Company’s developmental and exploratory drilling and seismic activities. No assurance can be given as to the availability or terms of any such additional financing that may be required or that financing will continue to be available under the existing or new financing arrangements. If additional capital sources are not available to the Company, its drilling, seismic and other activities may be curtailed and its business, financial conditions and results of operations could be materially adversely affected.

As of December 31, 2001, the Company had total indebtedness of $6.7 million. The Company’s indebtedness could have important consequences. For example, it could (i) increase the Company’s vulnerability to adverse economic and industry conditions; (ii) require the Company to dedicate a substantial portion of its cash flow from operations to payments on indebtedness, thereby reducing the availability of its cash flow to fund working capital, capital expenditures and other general corporate purposes; (iii) limit the Company’s flexibility in planning for, or reacting to, changes in its business and the oil and gas industry; (iv) place the Company at a disadvantage compared to its competitors that have less debt and (v) limit the Company’s ability to borrow additional funds. In addition, failing to comply with debt covenants could result in an event of default which, if not cured or waived, could adversely affect the Company.

As of December 31, 2001, the Company’s directors, executive officers and certain of their affiliates, beneficially owned approximately 20% of the Company’s outstanding Common Stock. Guardian Energy Management Corp. (“Guardian”) also owns approximately 19% of the Company’s outstanding stock. Accordingly, if these stockholders act together, as a group, they will be able to substantially control the outcome of stockholder votes, including votes concerning the election of directors, the adoption or amendment of provisions in the Company’s Certificate of Incorporation or Bylaws and the approval of mergers or 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 the management or direction of the Company. These factors also may have the effect of delaying or preventing a change in the management or voting control of the Company.

more difficult. Among other things, the Company’s Certificate of Incorporation and/or Bylaws: (i) provide for a classified Board of Directors serving staggered three-year terms; (ii) impose restrictions on who may call a special meeting of stockholders; (iii) include a requirement that stockholder action be taken only by unanimous written consent or at stockholder meetings; (iv) specify certain advance notice requirements for stockholder nominations of candidates for election to the Board of Directors and certain other stockholder proposals; and (v) impose certain restrictions and supermajority voting requirements in connection with specified business combinations not approved in advance by the Company’s Board of Directors. In addition, the Company’s Board of Directors, without further action by the stockholders, may cause the Company to issue up to 2.0 million shares of preferred stock, $0.01 par value (“Preferred Stock”), on such terms and with such rights, preferences and designations as the Board of Directors may determine. Issuance of such Preferred Stock, depending upon the rights, preferences and designations thereof, may have the effect of delaying, deterring or preventing a change in control of the Company. Further, certain provisions of the Delaware General Corporation Law (the “Delaware Law”) impose restrictions on the ability of a third party to effect a change in control and may be considered disadvantageous by a stockholder.

The Company’s Common Stock currently is traded on the Nasdaq National Market. Under the Nasdaq National Market rules a company will be de-listed if minimum closing stock bid drops below $1.00 per share for 30 consecutive trading days. On February 15, 2002, the Company received notice that its stock has failed to meet these minimum bid requirements. The notice further stated that if the closing bid for the Company’s Common Stock does not meet or exceed $1.00 for ten consecutive trading days following the date of the notice, Nasdaq will institute de-listing proceedings. Since receipt of the notice the closing bid price for the Company’s Common Stock has not met or exceeded $1.00 and it is not likely to prior to the end of the 90-day period. In the event Nasdaq institutes de-listing procedures on the Company’s stock, the Company would explore other possibilities such as listing on the Nasdaq SmallCap Market. If the Company’s stock were de-listed from the Nasdaq National Market and subsequently not listed on the Nasdaq SmallCap Market or other exchange or market, the Company’s stockholders would find it more difficult to dispose of their shares or obtain accurate quotations as to their market value, and the market price of the Company’s stock would likely decline further.

This annual report on Form 10-K includes forward-looking statements made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements can be identified by the words “anticipates,” “expects,” “intends,” “plans,” “projects,” “believes,” “estimates” and similar expressions. The Company has based the forward-looking statements relating to its operations on current expectations, estimates and projections about the Company and the oil and gas industry in general. These statements are not guarantees of future performance and involve risks, uncertainties and assumptions that the Company cannot predict. In addition, the Company has based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, the Company’s actual outcomes and results may differ materially from what is expressed or forecasted in the forward-looking statements. Any differences could result from a variety of factors including the following: fluctuations in crude oil and natural gas prices; failure or delays in achieving expected production from oil and gas development projects; uncertainties inherent in predicting oil and gas reserves and oil and gas reservoir performance; lack of exploration success; disruption or interruption of the Company’s production facilities due to accidents or political events; availability of future financing alternatives; availability of future equity infusions; ability to obtain promoted and carried working interests for future capital expenditures; liability for remedial actions under environmental regulations; liability resulting from litigation; world economic and political conditions; and changes in tax and other laws applicable to the Company’s business

	As of December 31,
	2001		2000
	(Dollars in thousands, except per unit data)
Net Proved Reserves:
Crude oil (MBbl)		601.3		329.5
Natural gas (MMcf)		7,325.4		10,511.7
Natural gas equivalent (MMcfe)		10,933.2		12,488.7
Net Proved Developed Reserves:
Crude oil (MBbl)		586.8		301.8
Natural gas (MMcf)		7,325.4		10,511.7
Natural gas equivalent (MMcfe)		10,846.2		12,322.5
Estimated future net revenues before income taxes(1)	$	20,414	$	91,174
Present value of estimated future net revenues before income taxes(2)	$	16,457	$	74,909
Standardized measure of discounted estimated future net cash flows(3)	$	16,457	$	66,674

In accordance with applicable requirements of the SEC, estimates of the Company’s proved reserves and future net revenues are made using sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation). Estimated quantities of proved reserves and future net revenues therefrom are affected by oil and natural gas prices, which have fluctuated widely in recent years. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond the control of the Company. The reserve data set forth in this Form 10-K 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 the Company, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing oil and natural gas prices, operating costs and other factors. The revisions may be material. Accordingly, reserve estimates often are different from the quantities of oil and natural gas that ultimately are recovered and are highly dependent upon

Estimates with respect to proved reserves that may be developed and produced in the future often are based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods generally are 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 and the variations may be substantial.

	Year Ended December 31,
	2001		2000		1999
	Gross	Net	Gross	Net	Gross	Net
Exploratory Wells:
Oil	—	—	3	0.6	1	0.4
Natural gas	—	—	1	0.2	1	1.0
Non-productive	9	4.1	3	0.9	4	2.2
Total	9	4.1	7	1.7	6	3.6
Development Wells(1):
Oil	4	1.2	1	0.1	1	0.9
Natural gas	1	0.2	—	—	1	0.6
Non-productive	1	—	—	—	1	0.4
Total	5	1.4	1	0.1	3	1.9

Delaware		38-3379776
(State or Other Jurisdiction of		(I.R.S. Employer Identification No.)
Incorporation or Organization)

3104 Logan Valley Road, Traverse City, Michigan		49685-0348
(Address of Principal Executive Offices)		(Zip Code)

Region	Oil		Natural Gas		Total
	Gross	Net	Gross	Net	Gross	Net
Mississippi Salt Basin	6	0.8	13	5.5	19	6.3
Michigan Basin/Other	1	0.1	1	1.0	2	1.1

Total	7	0.9	14	6.5	21	7.4