Item 1. Business.
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 Company was organized in connection with the combination (the "Combination Transaction") of MOC and interests in oil and natural gas properties owned by certain affiliated entities and interests in such properties owned by certain business partners and investors.
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 $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 and $10.3 million with respect to the Company's interest in 9 gross wells (5.5 net to the Company) for the year ended December 31, 1999. At December 31, 2000, the Company also had 3 gross wells (1.3 net to the Company) in the process of drilling and/or completing. In 2000, the Company also acquired undeveloped oil and gas properties valued for financial statement reporting purposes at $2.6 million from Eagle Investments Inc. ("Eagle") in exchange for shares of Company common stock and warrants. The Company currently plans to drill 19 wells (8.9 net to the Company) in 2001, 9 of which will be exploratory wells in the Mississippi Salt Basin. The Company anticipates 2001 capital expenditures for exploration and development activity in all of its areas of concentration will be approximately $10.0 million.
Core Exploration and Development Regions
Mississippi Salt Basin
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 1/2 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-Fredericksburg, Paluxy, Rodessa, Sligo, Hosston and Cotton Valley formations, all of which are normally pressured. The Company owns undeveloped leasehold interests in 44,376 gross acres (21,780 net to the Company) covering 21 known salt domes and related salt structures.
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 15 producing wells in the Mississippi Salt Basin that had an aggregate average production rate as of December 31, 2000 of 40.5 million cubic feet of natural gas equivalent per day ("MMcfe/d") gross (13.6 MMcfe/d net to the Company) at depths ranging from 10,800 to 17,900 feet. Since the Company began its exploration activity in Mississippi in 1993, it has participated in 28 2-D seismic supported and 11 3-D seismic supported wells drilled around 13 salt dome structures, with 14 of the 2-D wells (50%) and six of the 3-D wells (55%) establishing commercial production. At December 31, 2000, the Company also was in the process of drilling and/or completing 3 3-D wells (1.3 net to the Company). The Company has 9 gross wells (2.8 net to the Company) budgeted in 2001 for the Mississippi Salt Basin with a capital expenditure budget of $8.7 million, including $1.6 million for land and seismic costs. All 9 of the Mississippi Salt Basin wells budgeted for 2001 will be based on 3-D seismic data
Blackfeet Indian Reservation
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 for which the Tribe agreed the extension would not be unreasonably withheld. The terms of the extension were $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 20,000 acres with each set of two wells drilled, regardless of the outcome of the wells. A separate oil and gas lease covering 640 acres 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 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. In February 2001, the Company deposited the $0.5 million record anniversary payment stipulated in the Miller Agreement into an escrow account pending resolution of disputes with the Tribe mentioned above.
During 2000, the Company acquired 10,492 gross non-Tribal acres (10,492 net to the Company) on the Reservation. 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.
Joint Venture Exploration, Participation and Farm-out Agreements
The Company is a party to the following joint venture exploration, participation, farm-out and other agreements:
Mississippi Salt Basin Agreements
Since March 1993, the Company has entered into a series of joint venture exploration agreements and farm-out agreements with Amerada Hess Corporation, Liberty Energy Corporation, Bonray, Inc., Key Production Company Inc. ("Key"), Remington Oil & Gas Corp. ("Remington") and 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 20 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.
In October 1999, the Company executed a joint venture agreement with Remington covering multiple salt domes in the Mississippi Salt Basin. The terms of the joint venture arrangement provided an up front cash payment to the Company with the opportunity to participate in the drilling of five prospects in the Company's Mississippi Salt Basin Project. Remington earned a position in undeveloped acreage ranging from 14% to 40% working interest in the prospects by paying a disproportionate share of drilling costs in the five-well program.
Blackfeet Indian Reservation Agreements
See "Blackfeet Indian Reservation" for a discussion of the Company's joint venture agreements in that area.
Volumes, Prices and Production Costs
The following table sets forth information with respect to the Company's production volumes, average prices received and average production costs for the periods indicated:
Oil and Natural Gas Marketing and Major Customers
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 1998, 1999, and 2000, with spot market prices for crude oil falling below $10 per Bbl, and then rising over $34 per Bbl, and natural gas prices dropping below $1.00 per Mcf and then climbing up above $10 per Mcf during this three-year period. These wide 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, 2000, sales to the Company's three largest customers were approximately 65%, 16%, and 11%, 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.
Competition
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.
Title to Properties
The Company believes it has satisfactory title to all of its producing properties in accordance with standards generally accepted in the oil and gas industry. 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.
Mississippi Tax Abatement
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 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 enacted a bill that reduces the production tax 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 2000, the State of Mississippi notified the Company that all price ceilings had been exceeded which effectively phased out any tax abatements. The Company has paid the full production tax on all Mississippi oil and gas production since June 2000.
Governmental Regulation
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.
State Regulation
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.
Federal Regulation
The Company's sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. The Federal Energy 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 "unbundle" 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. Although Order No. 636 largely has been upheld on appeal, several appeals remain pending in related restructuring proceedings. It is difficult to predict when these remaining appeals will be completed or their impact on the Company.
FERC has announced several important transportation-related policy statements and proposed rule changes, including a statement of policy and a request for comments concerning alternatives to its traditional cost-of-service ratemaking methodology to establish the rates interstate pipelines may charge for their services. A number of pipelines have obtained FERC authorization to charge negotiated rates as one such alternative. In February 1997, FERC announced a broad inquiry into issues facing the natural gas industry to assist FERC in establishing regulatory goals and priorities in the post-Order No. 636 environment. 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 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.
Environmental Matters
The Company's operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences; 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.
Employees
As of March 20, 2001, 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.
Risks Associated with the Company's Business
Dependence on Exploratory Drilling Activities
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 2001 capital budget because of future uncertainties, including those described above. See "Management's Discussion and Analysis of Financial Condition and Results of Operations."
Operating Hazards and Uninsured Risks
The Company's operations are subject to hazards and risks inherent in drilling for and producing and transporting 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.
Volatility of Oil and Natural Gas Prices
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 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. It is impossible to predict future oil and natural gas price movements with certainty. A return to the significantly lower oil and gas prices experienced in 1998 and early 1999, 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.
Risks Associated with Management and Implementation of Growth Strategy
Any increase in the Company's activities as an operator will increase its exposure to operating hazards. The Company has relied in the past and expects to continue to rely on project partners and independent contractors, including geologists, geophysicists and engineers, that have provided the Company with seismic survey planning and management, project and prospect generation, land acquisition, drilling and other services. As the Company increases the number of projects it is evaluating or in which it is participating, there will be additional demands on the Company's financial, technical, 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 continue its growth 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.
Reserve Replacement Risk
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.
Marketability of Production
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.
Dependence on Key Personnel
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.
Technological Changes
The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new products and services utilizing new technologies. As others use or develop new 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.
Substantial Capital Projects
The Company makes and will continue to make capital expenditures in its exploration and development projects. The Company intends to finance these capital expenditures with cash flow from operations. 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.
Indebtedness
As of December 31, 2000, the Company had total indebtedness of $12.2 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.
Influence of Certain Stockholders
As of December 31, 2000, the Company's directors, executive officers and certain of their affiliates, beneficially owned approximately 41% of the Company's outstanding Common Stock. Guardian Energy Management Corp. ("Guardian") also owns approximately 19% of the Company's outstanding stock. Accordingly, these stockholders, as a group, may be able to control the outcome of stockholder votes, including votes concerning the election of directors, the adoption or amendment of provisions in the Company's Certificate of Incorporation or Bylaws and the approval of mergers 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.
Certain Antitakeover Considerations
The Company's Certificate of Incorporation and Bylaws include certain provisions that may have the effect of delaying, deterring or preventing a future takeover or change in control of the Company without the approval of the Company's Board of Directors. Such provisions also may render the removal of directors and management 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.
Forward-Looking Statements
This annual report on Form 10-K includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. 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; 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.
Item 2.
Item 2. Properties.
Oil and Natural Gas Reserves
The Company's estimated total proved reserves of oil and natural gas as of December 31, 2000 and 1999, and the present values of estimated future net revenues attributable to these reserves as of those dates were as follows:
- -------- (1) The average prices for crude oil were $23.36 per Bbl at December 31, 2000 and $22.29 per Bbl at December 31, 1999. The average prices for natural gas were $9.55 per Mcf at December 31, 2000 and $2.12 per Mcf at December 31, 1999.
(2) The present value of estimated future net revenues attributable to the Company's reserves was prepared using constant prices as of the calculation date, discounted at 10% per annum on a pre-tax basis.
(3) The standardized measure of discounted estimated future net cash flows represents discounted estimated future net cash flows attributable to the Company's reserves after income taxes, calculated in accordance with Statement of Financial Accounting Standards ("SFAS") No. 69. The 2000 balance was computed using year end prices that were significantly higher than historical levels. Using a price of $5.02 per Mcfe which represents the February 2001 period end prices, the standardized measure amount would be $57.2 million. The balance in 1999 has not been reduced by income taxes due to the tax basis of the properties and a net operating loss carryforward.
The reserve estimates reflected above, as of December 31, 2000 and 1999, were prepared by Miller and Lents, Ltd., independent petroleum engineers, and are part of their reserve reports on the Company's oil and natural gas properties.
In accordance with applicable requirements of the Securities and Exchange Commission ("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 the accuracy of the assumptions upon which they are based. The Company's estimated proved reserves have not been filed with or included in reports to any federal agency.
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.
Drilling Activities
The Company drilled, or participated in the drilling of, the following number of wells during the periods indicated:
- -------- (1) At December 31, 2000, the Company was in the process of drilling and/or completing 3 gross wells (1.3 net to the Company) that are not reflected in the table.
Productive Wells and Acreage
Productive Wells
The following table sets forth the Company's ownership interest as of December 31, 2000 in productive oil and natural gas wells in the areas indicated:
Productive wells consist of producing wells and wells capable of production, including wells waiting on pipeline connection. Wells that are completed in more than one producing horizon are counted as one well. Of the gross wells reported above, none are producing from multiple horizons.
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 such acreage contains proved reserves. A gross acre is an acre in which an interest is owned. A net acre is deemed to exist when the sum of fractional ownership interests in gross acres equals one. The number of net acres is the sum of the fractional interests owned in gross acres expressed as whole numbers and fractions thereof. The following table sets forth the approximate developed and undeveloped acreage in which the Company held a leasehold mineral or other interest at December 31, 2000:
- -------- (1) The Blackfeet Project in Montana is currently involved in litigation. The Company does not represent nor can it be assumed that the litigation will be favorably resolved. See "Item 3
Item 3. Legal Proceedings.
On May 1, 2000, the Company filed a lawsuit in the United States District Court for the District of Montana against K2 America Corporation and K2 Energy Corporation (collectively referred to in this section as "K2"). The Company's lawsuit includes certain claims of relief and allegations by the Company against K2, including breach of contract arising from failure by K2 to agree to escrow, repudiation, and rescission; specific performance; declaratory relief; partition of K2 lands that are subject to the K2 Agreement; negligence; and tortuous interference with contract. The lawsuit is on file with the United States District Court for the District of Montana, Great Falls Division and is not subject to protective order. Discovery is currently underway.
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 dated February 19, 1999, and pursuant to the K2 Agreement dated May 30, 1997.
The disputes for which the Company demands arbitration include, but are not limited to, the unreasonable withholding of a consent to a drilling extension as provided for in the Miller Agreement, as well as a determination by the Tribe dated March 16, 2000, that certain wells which the Company proposed to drill "would not satisfy the mandatory drilling obligations" under the K2 Agreement. The Company contends the K2 Agreement gives the Company, as lessee, and not the Tribe, the exclusive right to drill sites and determine well depths. The Company has had several meetings with the new Tribal Council elected in July 2000, and is working toward resolution of these matters.
The Company has been named as a defendant in a lawsuit filed June 1, 1999 by Energy Drilling Company ("Energy Drilling"), in the Parish of Catahoula, Louisiana arising from a blowout of the Victor P. Vegas #1 well that was drilled and operated by the Company. Energy Drilling, the drilling rig contractor on the well, is claiming damages related to their destroyed drilling rig and related costs amounting to approximately $1.2 million, plus interest, attorneys' fees and costs. In January 2001, the District Court judge ruled against the Company on two of the three claims filed in this case with damages left undetermined. This ruling is being appealed to the U.S. Fifth Circuit Court of Appeals. In the event the Company does not prevail in the appeal, any resulting damages owed would be covered by insurance.
The Company has been named in a lawsuit brought by Victor P. Vegas, the landowner of the surface location of the blowout well referenced above. The suit was filed July 20, 1999 in the Parish of Orleans, Louisiana, claiming unspecified damages related to environmental and other matters.
The Company has been named in a lawsuit brought by Charles Strictland, employee of BJ Services, Inc., on September 30, 1999. The suit claimed damages of $1.0 million for personal injuries allegedly suffered at a well site operated by the Company. The judge ruled in favor of the Company at the trial that was held March 8, 2001.
The Company had been named among several co-defendants in a lawsuit brought by Eric Parkinson, husband and personal representative of the Estate of Kelly Anne Parkinson (deceased). The amended complaint was filed December 13, 1999, in the County of Hillsdale, Michigan, claiming an unspecified amount plus interest and attorney fees for suffering the loss of the deceased care, comfort, society and support. Kelly Anne Parkinson was killed in an automobile accident on February 2, 1999, while traveling on a county road located next to land wherein the Company is lessee of underground mineral rights. The plaintiff alleged that the accident was the result of mud dragged on the road from the leased property and alleged that the Company was negligent in its duty to conduct its operations at the site with reasonable care. This case was settled and all claims dismissed in February 2001. All defense costs and the settlement amount will be covered by the Company's insurance.
The Company believes it has meritorious claims or defenses to the items discussed above and intends to vigorously pursue these lawsuits. The Company does not believe that the final outcome of these matters will have a material adverse effect on the Company's operating results, financial condition or liquidity. Due to the uncertainties inherent in litigation, however, no assurances can be given regarding the final outcome of each action. The Company currently believes any costs resulting from each of the lawsuits mentioned above would be covered by the Company's insurance.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders.
At the December 7, 2000 Special Meeting of Common Stockholders, the following proposals were voted upon:
. The issuance to Guardian of 3,703,704 shares of common stock upon the conversion of a $5.0 million promissory note.
. The issuance to Guardian of up to 13,062,500 shares of the Company's Common Stock upon the exercise by Guardian of warrants to purchase 1,562,500 shares of common stock for $1.35 per share, 2,500,000 shares of common stock for $2.50 per share, and 9,000,000 shares of common stock for $3.00 per share.
This proposal was approved by the Company's Stockholders.
. A transaction with Eagle, whereby Eagle would:
(a) pay the Company $500,000 in cash,
(b) assign to the Company a 50% interest in certain of the non- producing oil and gas leasehold interests which the Company had previously conveyed to Eagle, and
(c) grant the Company an exclusive right of first offer on the sale of Eagle's producing and non-producing asset base in the Mississippi Salt Basin,
in exchange for which the Company would:
(i) issue to Eagle 1,851,811 shares of Common Stock, and
(ii) issue to Eagle warrants to purchase 781,250 shares of Common Stock at $1.35 and 1,250,000 shares of common stock at $2.50 per share, respectively, as well as the subsequent right to exercise such warrants.
This proposal was approved by the Company's Stockholders.
PART II
Item 5.
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters.
The Company's Common Stock is traded on The Nasdaq National Market under the symbol "MEXP."
As of March 15, 2001, the Company estimates that there were approximately 2,200 beneficial holders of its Common Stock. The Company consummated the Offering on February 9, 1998. Before that time, there was no public market for the Company's Common Stock.
The following table sets forth the high and low bid information for the Company's Common Stock for the periods indicated, all as reported by The Nasdaq National Market:
The Company has not in the past, and does not intend to pay cash dividends on its Common Stock in the foreseeable future. The Company currently intends to retain earnings, if any, for the future operation and development of its business. The Company's credit facility contains provisions that may have the effect of limiting or prohibiting the payment of dividends.
On July 11, 2000, the Company entered into a Securities Purchase Agreement (the "Securities Purchase Agreement") with Guardian. Pursuant to the Securities Purchase Agreement, the Company issued to Guardian a convertible promissory note in the amount of $5.0 million, and three warrants exercisable, for 1,562,500, 2,500,000 and 9,000,000 shares of the Company's common stock, respectively. Conversion of the note and exercise of the warrants were subject to stockholder approval, which was obtained at a stockholder meeting on December 7, 2000.
On July 11, 2000, the Company also signed a letter agreement (the "Eagle Transaction") to acquire an interest in certain undeveloped oil and gas properties and $0.5 million in cash from Eagle, an affiliated entity controlled by C. E. Miller, the Chairman of the Company, in exchange for a total of 1,851,851 shares of common stock. In addition, Eagle was issued warrants exercisable for a total of 2,031,250 shares of common stock. Consummation of this transaction with Eagle also was approved by the stockholders at a meeting on December 7, 2000.
On July 11, 2000, the Company also entered into a Subscription Agreement with ECCO Investments, LLC ("ECCO"), pursuant to which ECCO purchased 370,370 shares of the Company's common stock for an aggregate purchase price of $0.5 million or $1.35 per share.
The securities issued in each of these transactions were issued in private placements exempt from registration under Section 4(2) of the Securities Act of 1933 and in conformity with the requirements of Rule 506 under Regulation D. Each of the purchasers in each of these transactions was an accredited investor. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" for a discussion of the use of the proceeds of these transactions.
Item 6.
Item 6. Selected Financial Data.
The following table presents selected historical consolidated financial data of the Company as of the dates and for the periods indicated. The historical consolidated financial data as of and for each of the five years in the period ended December 31, 2000 is derived from the consolidated financial statements which have been audited by Arthur Andersen LLP, independent public accountants. Earnings per share has been omitted for all periods prior to 1998 since such information is not meaningful and the historically combined Company (prior to the Combination Transaction) was not a separate legal entity with a single capital structure. The following data should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Consolidated Financial Statements.
- -------- (1) A $1.7 million one-time non-cash charge related to the Guardian Transaction (more fully described in Note 8 to the Consolidated Financial Statements) was recorded in interest expense in 2000. (2) Upon consummation of the Combination Transaction in 1998, the Company was required to record a one-time non-cash charge to earnings of $5.4 million in connection with establishing a deferred tax liability on the balance sheet in accordance with SFAS No. 109, "Accounting for Income Taxes."
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
Overview
Miller is an independent oil and gas exploration, development and production company that has developed a base of producing properties and inventory of prospects concentrated primarily in Mississippi. The Company was organized in connection with the Combination Transaction. The Combined Assets consist of MOC, interests in oil and natural gas properties from the Affiliated Entities and interests in such properties owned by certain business partners and investors. The Combination Transaction closed on February 9, 1998 in connection with the closing of 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. For further discussion of the Offering and the Combination Transaction, see Note 1 to the Consolidated Financial Statements.
The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including any general and administrative costs that are directly attributable to the Company's acquisition, exploration and development activities, are capitalized in a "full cost pool" as incurred. The Company records depletion of its full cost pool using the unit-of-production method. SEC Regulation S-X, Rule 4-10 requires companies reporting on a full cost basis to apply a ceiling test wherein the capitalized costs within the full cost pool, net of deferred income taxes, may not exceed the net present value of the Company's proved oil and gas reserves plus the lower of cost or market of unproved properties. Any such excess costs should be charged against earnings.
On December 7, 2000, the Common Stockholders of the Company approved certain transactions with Guardian and Eagle that, among other things, required the Company to record non-cash interest expense in the aggregate of approximately $1.7 million during the year ended December 31, 2000. These transactions are more fully discussed in Note 8 to the Consolidated Financial Statements.
Results of Operations
The following table summarizes production volumes, average sales prices and average costs for the Company's oil and natural gas operations for the periods presented (in thousands, except per unit amounts):
Year Ended December 31, 2000 compared to Year Ended December 31, 1999
Oil and natural gas revenues for the year ended December 31, 2000 increased 26% to $26.0 million from $20.7 million for the year ended December 31, 1999. Oil and natural gas revenues for the years ended December 31, 2000 and 1999 include approximately $2.0 million and $0.3 million of hedging losses, respectively (see "Risk Management Activities and Derivative Transactions" below). Production volumes for natural gas during the year ended December 31, 2000 decreased 24% to 5,762 MMcf from 7,594 MMcf for the year ended December 31, 1999. This decrease is attributable to declining production in the Mississippi Salt Basin properties. The Company installed compressors on all Company-operated properties in the Salt Basin and have reperforated and conducted other stimulation techniques to boost and/or stabilize production rates. The Company will continue to evaluate wells for various workover projects which will be funded by the Company's operating cash flows. The effect on natural gas production of the sale of the Company's Antrim Shale properties in Michigan and certain non-strategic producing properties in Louisiana and Texas in early 1999 have been offset by increased production from non-Antrim Shale production in the Michigan Basin during 2000. Average natural gas prices increased 59% to $3.60 per Mcf for the year ended December 31, 2000 from $2.27 per Mcf for the year ended December 31, 1999 due to improved natural gas commodity prices during 2000. Oil production volumes decreased 20% to 205 MBbls for the year ended December 31, 2000 compared to 256 MBbls the same period of 1999. Decreased production in the Mississippi Salt Basin accounted for 18% of the change with the remaining 2% decline being attributable to the sale of producing properties in Louisiana and Texas in early 1999 and in June 2000. The Company believes the installation of compressors in mid-2000 and the ongoing evaluation of the Company's producing wells for additional stimulation potential will help to
slow production decline rates. Average oil prices increased 91% to $25.82 per barrel during the year ended December 31, 2000 from $13.54 per barrel for the year ended December 31, 1999 as oil commodity prices rebounded in 2000.
Lease operating expenses ("LOE") and production taxes for the year ended December 31, 2000 increased 76% to $3.0 million from $1.7 million for the year ended December 31, 1999. LOE increased 27% to $1.9 million for 2000 compared to $1.5 million for 1999. This increase is comprised of a $0.6 million increase in expenses attributable to Mississippi Salt Basin wells and a $0.2 decrease in expenses resulting from the sale of producing properties in Michigan, Louisiana and Texas during 1999 and 2000. Compressor installation and related rental expenses and the costs of various reperforation and well stimulation projects account for the increased LOE on the Salt Basin properties.
Production taxes increased 450% to $1.1 million for 2000 compared to $0.2 million for 1999. Substantially all of this increase is attributable to the Salt Basin properties. Since June 2000, the average crude oil and natural gas prices exceeded the price ceiling established by the State of Mississippi, therefore exemption from the 7% production tax established by Mississippi Statute no longer applied. Also, since the Mississippi production tax is calculated by taking 7% of the gross value of the crude oil and natural gas, the upward trend in the amount of production tax expense followed the substantial increase in commodity prices that occurred during 2000.
Depreciation, depletion and amortization ("DD&A") expense for the year ended December 31, 2000 increased 9% to $17.5 million from $16.1 million for the year ended December 31, 1999.
General and administrative expense for the year ended December 31, 2000 decreased 25% to $2.1 million from $2.8 million for the same period in 1999. This decrease is attributable to the cost reduction plan implemented in May 1999. The primary components of the general and administrative expense reduction include; (1) a $0.7 million decrease in salaries, wages, and related employee benefits; (2) a $0.2 million decrease in legal and professional fees; and (3) a $0.1 million decrease in travel expenses. These decreases were offset by a $0.3 million reduction in the amount of capitalized general and administrative expenses in 2000.
Using unescalated period-end prices at December 31, 2000 of $8.65 per Mcfe, the Company had no impairment of oil and gas properties. Using unescalated period-end prices at December 31, 1999, of $2.38 per Mcfe, the Company would have recognized a non-cash impairment of oil and gas properties in the amount of approximately $1.2 million pre-tax. However, on the basis of the improvement in pricing experienced subsequent to period-end of $2.80 per Mcfe in March 2000, the Company determined that a writedown was not required.
Interest expense for the year ended December 31, 2000 increased 22% to $4.3 million from $3.5 million for the year ended December 31, 1999. This increase is attributable to $1.7 million of non-cash interest expense that was required to be recorded in connection with the Guardian Convertible Note Payable and the issuance of common stock warrants to Guardian, more fully discussed in "Liquidity and Capital Resources" below and in Note 8 to the Consolidated Financial Statements. Had the $1.7 million interest expense entry not been required, interest expense would have actually decreased by 25% to $2.6 million from $3.5 million. This decrease is attributable to a 58% reduction in total debt to $12.2 million at December 31, 2000 from $29.1 million at December 31, 1999 and the lower interest rate provided for under the Credit Facility agreement with the Company's new lender, Bank One, Texas, N.A. ("Bank One").
On July 19, 2000, the Company entered into a senior credit facility with Bank One which replaced the existing credit facility with Bank of Montreal. In connection with extinguishment of the debt with Bank of Montreal, the Company reported an extraordinary loss, net of income taxes of $0.2 million for the remaining unamortized debt expenses.
Net loss for the year ended December 31, 2000 decreased to $1.0 million from $2.0 million for the year ended December 31, 1999, as a result of the factors described above.
Year Ended December 31, 1999 compared to Year Ended December 31, 1998
Oil and natural gas revenues for the year ended December 31, 1999 decreased 1% to $20.7 million from $21.0 million for the year ended December 31, 1998. Oil and natural gas revenues for the years ended December 31, 1999 and 1998 include approximately ($0.3) million and $0.8 million of hedging (losses) gains, respectively (see "Risk Management Activities and Derivative Transactions" below). Production volumes for natural gas during the year ended December 31, 1999 decreased 15% to 7,594 MMcf from 8,953 MMcf for the year ended December 31, 1998. This decrease is attributable to the sales of the Company's Antrim Shale gas properties in Michigan and certain non-strategic properties in Texas and Louisiana that occurred earlier in 1999. The combined proceeds from these property sales amounted to $7.6 million of which $7.1 million was applied to the Company's outstanding debt balance.
The 23% decrease in natural gas production volumes attributable to these sold properties was partially offset by a 2% increase in natural gas produced from the Mississippi Salt Basin properties for the year ended December 31, 1999 compared to the same period of 1998. Average natural gas prices increased 11% to $2.27 per Mcf for the year ended December 31, 1999 from $2.05 per Mcf for the year ended December 31, 1998 due to improved natural gas commodity prices during the third and fourth quarters of 1999. Despite an 11% increase in oil production volumes for the Mississippi Salt Basin properties, total oil production for the year ended December 31, 1999 increased only 3% to 256 MBbls from 248 MBbls for the year ended December 31, 1998. Reduced oil production attributable to sold properties in Texas and Louisiana offset the production increases from the Mississippi Salt Basin properties. Average oil prices increased 27% to $13.54 per barrel during the year ended December 31, 1999 from $10.69 per barrel for the year ended December 31, 1998 as oil commodity prices rebounded in the third and fourth quarters of 1999.
Lease operating expenses and production taxes for the year ended December 31, 1999 decreased 49% to $1.7 million from $3.4 million for the year ended December 31, 1998. This decrease was primarily comprised of an approximate $1.0 million reduction in LOE attributable to properties in Texas, Louisiana and Michigan that were sold in 1999. Savings of approximately $0.5 million in 1999 compared to 1998 resulted from fewer well workovers in 1999 compared to 1998 and more efficient use of the Company's field operations personnel and much less dependence on contract pumping services. There was also an approximate $0.3 million decrease in production taxes associated with the sale of producing properties in 1999, partially offset by a $0.1 million increase in taxes attributable to new wells in Mississippi and Michigan that commenced initial production during 1999.
DD&A expense for the year ended December 31, 1999 increased 1% to $16.1 million from $16.0 million for the year ended December 31, 1998.
General and administrative expense for the year ended December 31, 1999 of $2.8 million was unchanged from the same period in 1998. Although general and administrative expense actually decreased by $0.4 million for 1999 compared to 1998 due to a cost reduction plan implemented in May 1999, fees received as reimbursement of general and administrative expense costs also decreased by $0.4 million, leaving reported general and administrative expense for the year ended December 31, 1999 unchanged from the level reported for the same period of the prior year.
Using unescalated period-end prices at December 31, 1999, of $2.38 per Mcfe, the Company would have recognized a non-cash impairment of oil and gas properties in the amount of approximately $1.2 million pre-tax. However, on the basis of the improvement in pricing experienced subsequent to period-end, the Company determined that a writedown was not required. At December 31, 1998, the Company recorded a non-cash cost ceiling writedown of $35.1 million. The writedown was the combined result of a large downward revision in oil and gas reserve quantities and depressed commodity prices. The large 8.2 Bcfe downward revision of the Company's proved oil and gas reserves at December 31, 1998 was comprised of a 4.3 Bcfe reduction in proved undeveloped reserves as a result of unsuccessful drilling activity and a 3.9 Bcfe reduction in proved producing reserves. Proved producing reserves decreased as a result of unanticipated pressure and production declines and by a reduction in the economic lives of producing reserves caused by the lower commodity prices being realized at December 31, 1998. Disappointing 2-D seismic-supported drilling results during 1998 and drilling
cost overruns on two non-operated properties also contributed to the cost ceiling writedown. The Company based its ceiling test determination on a price of $1.78 per Mcfe, which represented the March 1999 closing commodity prices.
Interest expense for the year ended December 31, 1999 increased 115% to $3.5 million from $1.6 million for the year ended December 31, 1998. This substantial interest expense increase is attributable to a higher average debt level in 1999 compared to 1998, due to substantial 3-D seismic acquisition costs, and exploration and development activity in the third and fourth quarters of 1998 that increased the outstanding debt balance. Also contributing to higher interest expense in 1999 was the interest expense associated with the Veritas Note Payable, more fully discussed in Note 7 to the Consolidated Financial Statements, and the prime plus 3.5% interest rate that became effective with the Second Amendment to the Credit Facility Agreement dated April 14, 1999, compared to the previous libor based rate effective during 1998.
Net loss for the year ended December 31, 1999 decreased to $2.0 million from $41.8 million for the year ended December 31, 1998, as a result of the factors described above.
Liquidity and Capital Resources
Liquidity
The Company's primary source of liquidity is cash generated from operations. Net cash provided by operating activities was $16.1 million, $12.9 million, and $18.8 million in 2000, 1999 and 1998, respectively. The increase in cash provided in 2000 compared to 1999 was primarily attributable to improved operating results because of the significantly increased commodity prices in 2000 and to drilling advances received from joint interest partners relating to the drilling of wells. The decrease in cash provided in 1999 compared to 1998 was principally due to the reduced payables in 1999 because of an effort by the Company to more effectively manage our cash flow requirements, including processing of payables on a more timely basis.
Net cash provided by (used in) investing activities was $(7.6) million, $4.0 million, and $(94.9) million in 2000, 1999, and 1998, respectively. The increase in cash used in 2000 compared to 1999 was due to a $13.3 million decrease in proceeds from the sale of oil and gas properties offset by a decrease in exploration and development expenditures of $1.7 million. The decrease in cash used in 1999 compared to 1998 was principally due to an increase in property sales of $11.2 million in 1999, a decrease in exploration and development expenditures of $36.7 million in 1999 and a decrease in the acquisition of properties of $51.0 million in 1999.
Net cash provided by (used in) financing activities was $(9.9) million, $(13.2) million, and $75.9 million in 2000, 1999, and 1998, respectively. The decrease in cash used in 2000 compared to 1999 was primarily a result of $7.0 million in proceeds from the issuance of common stock offset by a reduction in net borrowings on long-term debt. The decrease in cash provided in 1999 compared to 1998 was primarily a result of the proceeds from the Company's initial public offering in 1998 and a reduction in net borrowings in 1999.
Capital Resources
Historically, the Company's primary sources of capital have been funds generated by operations, and borrowings under bank credit facilities.
Concurrently with the Offering, a credit facility was entered into with Bank of Montreal, Houston Agency. The credit facility, as amended, required principal reductions and included certain negative covenants that imposed limitations on the Company and its subsidiary with respect to, among other things, distributions with respect to our capital stock, limitations on financial ratios, the creation or incurrence of liens, restrictions on proceeds from sales of oil and gas properties, the incurrence of additional indebtedness, making loans and investments and mergers and consolidations. The Company's obligations under the credit facility were secured by a lien on all of its real and personal property. Commencing April 1999, the interest rate under this facility was increased to Bank of Montreal's prime plus 3.5%.
On July 19, 2000, the Company entered into a new senior credit facility with Bank One, which replaced the existing credit facility with Bank of Montreal. The new credit facility has a 30-month term with an interest rate under the new credit facility is either Bank One prime plus 2% or LIBOR plus 4%, at the Company's option. The Company's obligations under the credit facility are secured by a lien on all of its real and personal property. The new credit facility required the Company to make monthly principal payments of $500,000 from August 1, 2000 until the borrowing base re-determination that occurred on January 1, 2001. The new borrowing base determined by Bank One as of December 31, 2000 is $9.0 million, less the amount due Amerada Hess Corporation ("AHC") in 2001. The next scheduled borrowing base re-determination with Bank One is in July 2001.
The Company made principal payments of approximately $14.4 million and $15.0 million, for the years ended December 31, 2000, and 1999, respectively, under the credit facility with Bank of Montreal and Bank One. At December 31, 2000, the outstanding debt balance under the Company's credit facility with Bank One was $7.5 million.
The Bank One credit facility includes certain negative covenants that impose restrictions on us with respect to, among other things, incurrence of additional indebtedness, limitations on financial ratios, making investments and mergers and consolidation.
On April 14, 1999, the Company issued a $4.7 million note payable to one of its suppliers, Veritas DGC Land, Inc. (the "Veritas Note"), for the outstanding balance due to Veritas for past services provided in 1998 and 1999. The principal obligation under the Veritas Note was originally due on April 15, 2001. On July 19, 2000, the note was amended as more fully described below.
On April 14, 1999, the Company also entered into an agreement (the "Warrant Agreement") to issue warrants to Veritas that entitle Veritas to purchase shares of common stock in lieu of receiving cash payments for the accrued interest obligations under the Veritas Note. The Warrant Agreement required the Company to issue warrants to Veritas in conjunction with the signing of the Warrant Agreement, as well as on the six and, at the Company's option, 12 and 18 month anniversaries of the Warrant Agreement. The warrants issued equal 9% of the then current outstanding principal balance of the Veritas Note. The number of shares issued upon exercise of the warrants issued on April 14, 1999, and on the six-month anniversary was determined based upon a five-day weighted average closing price of the Company's Common Stock at April 14, 1999. The exercise price of each warrant is $0.01 per share. On April 14, 1999, warrants exercisable for 322,752 shares of common stock were issued to Veritas in connection with execution of the Veritas Note. On October 14, 1999 and April 14, 2000, warrants exercisable for another 322,752 and 454,994 shares, respectively, of Common Stock were issued to Veritas. The Company ratably recognizes the prepaid interest into expense over the period to which it relates. For the years ended December 31, 2000 and 1999, the Company recognized non-cash interest expense of approximately $752,000 and $600,000, respectively, related to the Veritas Note Payable. The Warrant Agreement was also amended on July 19, 2000.
Under the terms of the amended note and warrant agreements, the maturity of the Veritas Note was extended from April 15, 2001 to July 21, 2003 and the expiration date for all warrants issued was extended until June 21, 2004. The annual interest rate has been reduced from 18% to 9 %, provided the entire note balance is paid in full by December 31, 2001. If all principal and interest under the Veritas Note is not paid by December 31, 2001, then the note bears interest at 13 % until paid in full. As of December 31, 2000, the Company has only recognized interest expense on the outstanding Veritas Note at 9 3/4% since it is believed that the principal balance will be paid in full by December 31, 2001. Interest accrues at the reduced rate from and after October 15, 2000 and is payable commencing April 15, 2001 and continuing on each October 15 and April 15 until principal is paid in full. Interest was required to be paid in warrants under the terms of the Warrant Agreement until the Company is in compliance with the net borrowing base formula as defined in the Bank One credit facility agreement, at which time interest will only be paid in cash.
Under the amended Veritas Note, a principal payment of $500,000 was made on July 19, 2000, the effective date of the amendment, and another $500,000 payment was made in December 2000. The balance due Veritas was $3.7 million at December 31, 2000 with the entire balance classified as long-term in the accompanying financial statements.
Any additional proceeds derived from the exercise of warrants issued or from other debt or equity transactions must be used to pay interest and principal on the amended Veritas Note until paid in full. Effective November 1, 2000, Veritas exercised 500,000 warrants to receive 496,923 shares (net of exercise price) of Company common stock.
In connection with the closing of the AHC property acquisition on February 9, 1998, the Company issued a non-interest bearing note payable to AHC (the "AHC Note"). The Company had obtained a six-month extension of the $1.0 million payment due AHC from February 2000 to August 2000. This payment was made on August 3, 2000. Also, the $1.5 million payment due February 2001 has been divided into three quarterly installments of $500,000 each, payable commencing February 2001. A substantial portion of the first quarter 2001 payment was made in December 2000.
Refer to Note 8 of the Consolidated Financial Statements for further information regarding capital resources, specifically the Guardian and Eagle Transactions in 2000.
At December 31, 2000, the Company had a working capital deficit of $0.3 million (excluding the current portion of long-term debt). Management plans to meet these working capital requirements from operational cash flows.
The Company anticipates 2001 capital expenditures will be approximately $10.0 million. Capital expenditures will be used to fund drilling and development activities, the acquisition of additional seismic data and processing and leasehold acquisitions and extensions in the Company's project areas. The actual amounts of capital expenditures and number of wells drilled may differ significantly from such estimates. Actual capital expenditures for the year ended December 31, 2000 were approximately $8.6 million. The Company also acquired undeveloped oil and gas properties valued for financial reporting purposes at $2.6 million from Eagle in exchange for shares of the Company's common stock and warrants, as more fully described in Note 8 to the Consolidated Financial Statements. The Company intends to fund its 2001 budgeted capital expenditures through operational cash flow.
The Company's revenues, profitability, future growth and ability to borrow funds or obtain additional capital, and the carrying value of its properties, substantially are dependent on prevailing prices of oil and natural gas. The Company cannot predict future oil and natural gas price movements with certainty. A return to the significantly lower oil and gas prices experienced in 1998 and early 1999, as compared to historical averages, would likely have an adverse effect on the Company's financial condition, liquidity, ability to finance capital expenditures and results of operations. Lower oil and natural gas prices also may reduce the amount of reserves that can be produced economically by the Company.
The Company has experienced and expects to continue to experience substantial working capital requirements primarily due to the Company's active exploration and development program. While the Company believes that cash flow from operations and improved commodity prices should allow the Company to implement its present business strategy through 2001, additional debt or equity financing may be required during the remainder of 2001 and in the future to fund the Company's growth, development and exploration program, and to satisfy its existing obligations. The failure to obtain and exploit such capital resources could have a material adverse effect on the Company, including further curtailment of its exploration and other activities.
Risk Management Activities and Derivative Transactions
The Company uses a variety of derivative instruments ("derivatives") to manage exposure to fluctuations in commodity prices and interest rates. To qualify for hedge accounting, derivatives must meet the following criteria: (i) the item to be hedged exposes the Company to price or interest rate risk; and (ii) the derivative reduces that exposure and is designated as a hedge.
Commodity Price Hedges
The Company periodically enters into certain derivatives (e.g., NYMEX futures contracts) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce the exposure to price fluctuations. The Company's hedging arrangements apply to only a portion of its production, provide only partial price protection against declines in oil and natural gas prices and limit potential gains from future increases in prices. Such hedging arrangements may expose the Company to risk of financial loss in certain circumstances, including instances where production is less than expected, the Company's customers fail to purchase contracted quantities of oil or natural gas or a sudden unexpected event materially impacts oil or natural gas prices. For financial reporting purposes, gains and losses related to hedging are recognized as oil and natural gas revenues during the period the hedge transactions occur. The Company expects that the amount of hedge contracts that it has in place will vary from time to time. For the years ended December 31, 2000, 1999, and 1998, the Company hedged 54%, 45%, and 36% of its oil and gas production, respectively, and as of December 31, 2000, the Company had 2.0 Bcfe of open oil and natural gas contracts for the months of January 2001 through December 2001. Refer to Note 10 of the Consolidated Financial Statements for further discussion of price risk management and derivative activities.
New Accounting Standard
In June 1998, the Financial Accounting Standards Board ("FASB") issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", amended by Statement No. 137, "Accounting for Derivative Instruments and Hedging Activities-Deferral of the Effective Date of FASB Statement No. 133" and Statement No. 138, "Accounting for Certain Derivatives and Certain Hedging Activities" (hereinafter collectively referred to as SFAS No. 133). SFAS No. 133 requires that every derivative instrument, including certain derivative instruments embedded in other contracts, be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS No. 133 requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting.
SFAS No. 133 has been adopted by the Company as of January 1, 2001 and the Company has completed the process of identifying all derivative instruments, determining fair market values of derivatives designating and documenting hedge relationships, and evaluating the effectiveness of those hedge relationships.
Certain financial derivative contracts used to hedge the price risk on future production qualify under the provisions of SFAS No. 133 as cash flow hedges. These contracts are required to be recognized at their fair value in the Consolidated Balance Sheet as an asset or liability. Management estimates that the effect of adopting SFAS No. 133 as of January 1, 2001 would increase liabilities by approximately $5.7 million with a corresponding decrease in other comprehensive income in the Consolidated Statement of Equity since the contracts outstanding on the date meet the specific hedge accounting criteria. Approximately $3.9 million of the $5.7 million amount represents the liability estimated for the contracts settling in the first quarter of 2001. The amount of hedge loss actually realized on these contracts settled in the first quarter of 2001 was $2.2 million. Management estimates that the liability and corresponding balance of other comprehensive income that would be reported in the Consolidated Statement of Equity is approximately $1.4 million as of March 10, 2001.
Effects of Inflation and Changes in Price
Crude oil and natural gas commodity prices have been volatile and unpredictable during 1998, 1999 and 2000, with crude oil prices falling below $10 per Bbl and rising close to $34 per Bbl, and natural gas prices dropping below $1 per Mcf and then climbing up above $10 per Mcf during this two-year time period. These wide fluctuations have had a significant impact on the Company's results of operations, cash flow and liquidity. Recent rates of inflation have had a minimal effect on the Company.
Environmental and Other Regulatory Matters
The Company's business is subject to certain federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of, 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 the Company believes it is in substantial compliance with all applicable laws and regulations, the requirements imposed thereby frequently change and become subject to interpretation, and the Company is unable to predict the ultimate cost of compliance with these requirements or their effect on its operations. Any suspensions, terminations or inability to meet applicable bonding requirements could materially adversely affect the Company's business, financial condition and results of operations. Although significant expenditures may be required to comply with governmental laws and regulations applicable to the Company, compliance has not had a material adverse effect on the earnings or competitive position of the Company. Future regulations may add to the cost of, or significantly limit, drilling activity.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Market Risk Information
The market risk inherent in the Company's derivatives is the potential loss arising from adverse changes in commodity prices and interest rates. The prices of oil and natural gas are subject to fluctuations resulting from changes in supply and demand. To reduce price risk caused by the market fluctuations, the Company's policy is to hedge (through the use of derivatives) future production. Because commodities covered by these derivatives are substantially the same commodities that the Company sells in the physical market, no special correlation studies other than monitoring the degree of convergence between the derivative and cash markets are deemed necessary. The changes in market value of these derivatives have a high correlation to the price changes of oil and natural gas.
A sensitivity analysis model was used to calculate the fair values of the Company's derivatives rates in effect at December 31, 2000. The sensitivity analysis involved increasing or decreasing the forward rates by a hypothetical 10% and calculating the resulting unfavorable change in the fair values of the derivatives. The results of this analysis, which may differ from actual results, showed this type of change would not have a material impact on the fair value of the derivatives previously stated (as discussed in the "New Accounting Standard" section above).
Item 8.
Item 8. Financial Statements and Supplementary Data.
The information required hereunder is included in this report as set forth in the "Index to Financial Statements" on Page.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant.
The information regarding directors of the Company contained under the captions "Board of Directors," "Executive Officers" and "Section 16(a) Beneficial Ownership Reporting Compliance" in the definitive Proxy Statement for the Company's annual meeting of stockholders to be held on May 25, 2001 is here incorporated by reference.
Item 11.
Item 11. Executive Compensation.
The information contained under the captions "Compensation of Directors" and "Executive Compensation" in the definitive Proxy Statement for the Company's annual meeting of stockholders to be held on May 25, 2001 is here incorporated by reference.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The information contained under the captions "Voting Securities," "Security Ownership of Certain Beneficial Owners" and "Security Ownership of Management" in the definitive Proxy Statement for the Company's annual meeting of stockholders to be held on May 25, 2001 is here incorporated by reference.
Item 13.
Item 13. Certain Relationships and Related Transactions.
The information contained under the captions "Voting Securities," "Security Ownership of Certain Beneficial Owners" and "Security Ownership of Management" in the definitive Proxy Statement for the Company's annual meeting of stockholders to be held on May 25, 2001 is here incorporated by reference.
PART IV
Item 14.
Item 14. Exhibits, Financial Statements, Schedules, and Reports on Form 8-K.
Item 14(a)(1). Financial Statements. See "Index to Financial Statements" set forth on page.
Item 14(a)(2). Financial Statement Schedules. Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company's financial statements and related notes.
Item 14(a)(3). Exhibits. The following exhibits are filed as a part of this report.
- -------- * Management contract or compensatory plan or arrangement.
Item 14(b). The Company filed no reports on Form 8-K during the last quarter of 2000.
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, thereunto duly authorized.
MILLER EXPLORATION COMPANY
/s/ Kelly E. Miller By __________________________________ Kelly E. Miller President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
/s/ Deanna L. Cannon *By _________________________ Deanna L. Cannon Attorney-in-Fact
ARTHUR ANDERSEN LLP
Report of Independent Public Accountants
To the Board of Directors and Stockholders of Miller Exploration Company:
We have audited the accompanying consolidated balance sheets of MILLER EXPLORATION COMPANY (a Delaware corporation) and subsidiaries as of December 31, 2000 and 1999, and the related consolidated statements of operations, equity, and cash flows for each of the three years in the period ended December 31, 2000. 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 in accordance with auditing standards generally accepted in the 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Miller Exploration Company and subsidiaries as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States.
/s/ Arthur Andersen LLP
Detroit, Michigan March 9, 2001
MILLER EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)
The accompanying notes are an integral part of these Consolidated Financial Statements.
MILLER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
The accompanying notes are an integral part of these Consolidated Financial Statements.
MILLER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF EQUITY
(In thousands)
The accompanying notes are an integral part of these Consolidated Financial Statements.
MILLER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
The accompanying notes are an integral part of these Consolidated Financial Statements.
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Organization and Nature of Operations
The Combination Transaction
Miller Exploration Company ("Miller" or the "Company") was formed as a Delaware corporation in November 1997 to serve as the surviving company upon the completion of a series of combination transactions (the "Combination Transaction"). The first part of the Combination Transaction included the following activities: Miller acquired all of the outstanding capital stock of Miller Oil Corporation ("MOC"), the Company's predecessor, and certain oil and gas interests (collectively, the "Combined Assets") owned by Miller & Miller, Inc., Double Diamond Enterprises, Inc., Frontier Investments, Inc., Oak Shores Investments, Inc., Eagle Investments, Inc. (d/b/a Victory, Inc.) and Eagle International, Inc. (the "affiliated entities," all Michigan corporations owned by Miller family members who were beneficial owners of MOC) in exchange for an aggregate consideration of approximately 5.3 million shares of Common Stock of Miller. The operations of all of these entities had been managed through the same management team, and had been owned by the same members of the Miller family. Miller completed the Combination Transaction concurrently with consummation of an initial public offering (the "Offering").
Initial Public Offering
On February 9, 1998, the Company completed the Offering of its Common Stock and concurrently completed the Combination Transaction. On that date, the Company sold 5.5 million shares of its Common Stock for an aggregate purchase price of $44.0 million. On March 9, 1998, the Company sold an additional 62,500 shares of its Common Stock for an aggregate purchase price of $0.5 million, pursuant to the exercise of the underwriters' over-allotment option.
The consolidated financial statements as of and for the year ended December 31, 1998 include the accounts of the Company and its subsidiaries after taking into effect the Offering and the Combination Transaction.
Other Transactions Completed Concurrently With the Initial Public Offering
In addition to the above combined activities of the Company, the second part of the Combination Transaction that was consummated concurrently with the Offering was the exchange by the Company of an aggregate of approximately 1.6 million shares of Common Stock for interests in certain other oil and gas properties that were owned by non-affiliated parties. Because these interests were acquired from individuals who were not under the common ownership and management of the Company, these exchanges were accounted for under the purchase method of accounting. Under that method, the properties were recorded at their estimated fair value at the date on which the exchange was consummated (February 9, 1998).
In November 1997, the Company entered into a Purchase and Sale Agreement, whereby the Company acquired interests in certain crude oil and natural gas producing properties and undeveloped properties from Amerada Hess Corporation ("AHC") for $48.8 million, net of post-closing adjustments. This purchase was consummated concurrently with the Offering. This acquisition was accounted for under the purchase method of accounting and was financed with the use of proceeds from the Offering and with new bank borrowings.
In February 1998, MOC terminated its S corporation status which required the Company to reclassify combined equity and retained earnings as additional paid- in capital.
Principles of Consolidation
The consolidated financial statements of the Company include the accounts of the Company and its subsidiaries after elimination of all intercompany accounts and transactions.
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Principles of Combination
The Combination Transaction was accounted for as a reorganization of entities under common control in a manner similar to a pooling-of-interests, as prescribed by Securities and Exchange Commission ("SEC") Staff Accounting Bulletin No. 47 because of the high degree of common ownership among, and the common control of, the combined entities.
Nature of Operations
The Company is a domestic, independent energy company engaged in the exploration, development and production of crude oil and natural gas. The Company has established exploration efforts concentrated primarily in the Mississippi Salt Basin of central Mississippi .
(2) Summary of Significant Accounting Policies
Oil and Gas Properties
The Company follows the full cost method of accounting and capitalizes all costs related to its exploration and development program, including the cost of nonproductive drilling and surrendered acreage. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and gas wells, together with internal costs directly attributable to property acquisition, exploration and development activities. Under this method, the proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs, and gains and losses are not recognized. The capitalized costs are amortized on an overall unit-of-production method based on total estimated proved oil and gas reserves. Additionally, certain costs associated with major development projects and all costs of unevaluated leases are excluded from the depletion base until reserves associated with the projects are proved or until impairment occurs.
To the extent that capitalized costs within the full cost pool, net of deferred income taxes, exceed the sum of discounted estimated future net cash flows from proved oil and gas reserves (using unescalated prices and costs and a 10% per annum discount rate) and the lower of cost or market value of unproved properties, such excess costs are charged against earnings. Using unescalated period-end prices at December 31, 2000, of $8.65 per Mcfe, the Company had no impairment of oil and gas properties. Using unescalated period- end prices at December 31, 1999, of $2.38 per Mcfe, the Company would have recognized a non-cash impairment of oil and gas properties in the amount of approximately $1.2 million pre-tax. However, on the basis of the improvements in pricing experienced subsequent to period-end of $2.80 per Mcfe in March 2000, the Company determined that a writedown was not required.
At December 31, 1998, the Company recognized a non-cash cost ceiling writedown in the amount of $35.1 million. The Company based its ceiling test determination on a price of $1.78 per Mcfe, which represented the March 1999 closing commodity prices. Had the Company used unescalated period-end prices at December 31, 1998 of $1.92 per Mcfe, the Company would have recognized a cost ceiling writedown of $31.1 million.
Property and Equipment
Property and equipment is included in other assets in the accompanying consolidated Balance Sheets and consists primarily of office furniture, equipment and computer software and hardware. Depreciation and amortization are calculated using straight-line and accelerated methods over the estimated useful lives of the related assets. The estimated useful lives for each category of fixed assets are: buildings and improvements (10 -20 years); office furniture and equipment (7-10 years) and computer software and hardware (3-5 years).
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Revenue Recognition
Crude oil and natural gas revenues are recognized as production takes place and the sale is completed and the risk of loss transfers to a third party purchaser.
Inventories
Inventories consist of oil field casing, tubing and related equipment for wells. Inventories are valued at the lower of cost (first-in, first-out method) or market.
Cash and Cash Equivalents
Cash and cash equivalents are comprised of cash and U.S. Government securities with original maturities of three months or less.
Reclassifications
Certain reclassifications have been made to the prior year financial statements to conform with the 2000 presentation.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the reporting periods. Accordingly, actual results could differ from these estimates. Significant estimates include depreciation, depletion and amortization of proved oil and natural gas properties. Oil and natural gas reserve estimates, which are the basis for unit-of-production depletion and the cost ceiling test, are inherently imprecise and are expected to change as future information becomes available.
Comprehensive Income (Loss)
As of December 31, 2000 and 1999, the Company does not have any comprehensive income (loss) other than the net income (loss) for the periods presented.
Other
For significant accounting policies regarding income taxes, see Note 4; for earnings per share, see Note 5; for financial instruments, see Note 9; for risk management activities and derivative transactions, see Note 10; and for stock- based compensation, see Note 12.
(3) Restricted Cash
In 1999, the Company entered into escrow agreements at the request of certain joint interest partners regarding the drilling of certain wells operated by the Company. Terms of the escrow agreements require the parties to the agreements to deposit their proportionate share of the estimated costs of drilling each subject well into a separate escrow account. The escrow account is controlled by an independent third party agent and is restricted to the sole purpose of processing payments to vendors and suppliers for charges and expenses associated with the drilling of the wells covered by the escrow agreements. The amounts recorded as restricted cash in the Consolidated Balance Sheets represent the Company's share of funds on deposit in the escrow accounts. Once the agreed upon drilling procedures have been completed, any remaining funds in the escrow accounts will be promptly returned to the respective joint interest partners in the same proportion as the original contributions into the escrow accounts.
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(4) Income Taxes
The Company accounts for income taxes under the provisions of Statement of Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income Taxes." SFAS No. 109 requires the asset and liability approach for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases.
Before consummation of the Offering, the Company and the affiliated entities either elected to be treated as S corporations under the Internal Revenue Code or were otherwise not taxed as entities for federal income tax purposes. The taxable income or loss has therefore been allocated to the equity owners of the Company and the affiliated entities. Due to the use of different methods for tax and financial reporting purposes in accounting for various transactions, the Company has temporary differences between its tax basis and financial reporting basis. Had the Company been a taxpaying entity before consummation of the Offering, a deferred tax liability of approximately $5.4 million would have been recorded for this difference, with a corresponding reduction in retained earnings.
Included in the deferred income tax provision for the year ended December 31, 1998, is a one-time non-cash accounting charge of $5.4 million to record net deferred tax liabilities, for the differences between tax basis and financial reporting basis, upon consummation of the Offering and the termination of MOC's S corporation status. The effective income tax rate for the Company for the years ended December 31, 2000, 1999 and 1998, was different than the statutory federal income tax rate for the following reasons (in thousands):
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The principal components of the Company's deferred tax assets (liabilities) recognized in the balance sheet as of December 31, 2000 and 1999 are as follows (in thousands):
SFAS No. 109 requires that the Company record a valuation allowance when it is more likely than not that some portion or all of the deferred tax assets will not be realized. In the fourth quarter of 1998, the Company recorded a $35.1 million cost ceiling writedown. The writedown and significant tax net operating loss carryforwards resulted in a net deferred tax asset at December 31, 1998. The Company believes it is more likely than not that a portion of the deferred tax assets will not be realized, therefore, the Company has recorded a valuation allowance. At December 31, 2000, the Company had regular tax net operating loss carryforwards of approximately $34.0 million. This loss carryforward amount will expire during 2017. The Company also had a percentage depletion carryforward of approximately $1.2 million at December 31, 2000, which is available to offset future federal income taxes payable and has no expiration date.
(5) Earnings Per Share
In accordance with the provisions of SFAS No. 128, "Earnings per Share," basic earnings per share is computed on the basis of the weighted-average number of common shares outstanding during the periods. Diluted earnings per share is computed based upon the weighted-average number of common shares plus the assumed issuance of common shares for all potentially dilutive securities.
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The computation of earnings per share for the year ended December 31, 2000, 1999 and 1998 is as follows (in thousands, except per share data):
Options and warrants were not included in the computation of diluted earnings per share for the years ended December 31, 2000, 1999 and 1998 because their effect was antidilutive.
(6) Net Production Payments
During 1995, the Company transferred a limited-term working interest, based on specified volumes, in certain natural gas producing properties to Miller Shale Limited Partnership ("MSLP"), an affiliated entity. Under the terms of the agreement, the Company received payments equal to 97% of the net profits from MSLP, as defined in the agreement, arising from the production of those properties. The payments received by the Company were reflected on a gross basis in the accompanying consolidated financial statements and the associated proved reserves also were reflected in the accompanying supplemental oil and gas disclosures to the consolidated financial statements.
In June 1999, the Company sold its interest in the above properties, which included the above-referenced net production payment stream for $4.5 million of which $4.0 million was used to reduce the Company's outstanding Credit Facility balance (see Note 7).
(7) Long-Term Debt
Bank Debt
Concurrently with the Offering, the Company entered into a credit facility (the "Credit Facility") with Bank of Montreal, Houston Agency ("Bank of Montreal"). The Credit Facility, as amended, required principal reductions and included certain negative covenants that imposed limitations on the
Company and its subsidiary with respect to, among other things, distributions with respect to capital stock, limitations on financial ratios, the creation or incurrence of liens, restrictions on proceeds from sales of oil and
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
gas properties, the incurrence of additional indebtedness, making loans and investments and mergers and consolidations. The obligations under the Credit Facility were secured by a lien on all real and personal property of the Company. Commencing April 1999, the interest rate under this facility was increased to Bank of Montreal's prime rate plus 3.5%.
On July 11, 2000, a principal payment of $4.9 million was made to reduce the outstanding balance under the Credit Facility to $11.5 million. On July 19, 2000, the Company entered into a new senior credit facility with Bank One, which replaced the existing credit facility with Bank of Montreal. The new credit facility has a 30-month term with an interest of either the Bank One prime rate plus 2% or LIBOR plus 4% at the Company's option. Under the new credit facility the Company was required to make monthly payments of $500,000 from August 1, 2000, until the borrowing base re-determination that occurred on January 1, 2001. The new borrowing base determined by Bank One as of December 31, 2000 is $9.0 million, less the amount due AHC in 2001. The next scheduled borrowing base re-determination with Bank One is in July 2001. The outstanding Bank One credit facility balance is $7.5 million at December 31, 2000.
The Bank One credit facility includes certain covenants that impose restrictions on the Company with respect to, among other things, incurrence of additional indebtedness, limitations on financial ratios, making investments and mergers and consolidation. The obligations under the new credit facility are secured by a lien on all of the Company's real and personal property.
Other
On April 14, 1999, the Company issued a $4.7 million note payable to one of its suppliers, Veritas DGC Land, Inc. (the "Veritas Note"), for the outstanding balance due to Veritas for past services provided in 1998 and 1999. The principal obligation under the Veritas Note was originally due on April 15, 2001. On July 19, 2000, the note was amended as more fully described below.
On April 14, 1999, the Company also entered into an agreement (the "Warrant Agreement") to issue warrants to Veritas that entitle Veritas to purchase shares of common stock in lieu of receiving cash payments for the accrued interest obligations under the Veritas Note. The Warrant Agreement required the Company to issue warrants to Veritas in conjunction with the signing of the Warrant Agreement, as well as on the six and, at the Company's option, 12 and 18 month anniversaries of the Warrant Agreement. The warrants issued equal 9% of the then current outstanding principal balance of the Veritas Note. The number of shares issued upon exercise of the warrants issued on April 14, 1999, and on the six-month anniversary was determined based upon a five-day weighted average closing price of the Company's Common Stock at April 14, 1999. The exercise price of each warrant is $0.01 per share. On April 14, 1999, warrants exercisable for 322,752 shares of common stock were issued to Veritas in connection with execution of the Veritas Note. On October 14, 1999 and April 14, 2000, warrants exercisable for another 322,752 and 454,994 shares, respectively, of Common Stock were issued to Veritas. The Company ratably recognizes the prepaid interest into expense over the period to which it relates. For the years ended December 31, 2000 and 1999, the Company recognized non-cash interest expense of approximately $752,000 and $600,000, respectively, related to the Veritas Note Payable. The Warrant Agreement was also amended on July 19, 2000.
Under the terms of the amended note and warrant agreements, the maturity of the Veritas Note was extended from April 15, 2001 to July 21, 2003 and the expiration date for all warrants issued was extended until June 21, 2004. The annual interest rate has been reduced from 18% to 9 %, provided the entire note balance is paid in full by December 31, 2001. If all principal and interest under the Veritas Note is not paid by December 31, 2001, then the note bears interest at 13 % until paid in full. As of December 31, 2000, the
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Company has only recognized interest expense on the outstanding Veritas Note at 9 3/4% since it is believed that the principal balance will be paid in full by December 31, 2001. Interest accrues at the reduced rate from and after October 15, 2000 and is payable commencing April 15, 2001 and continuing on each October 15 and April 15 until principal is paid in full. Interest was required to be paid in warrants under the terms of the Warrant Agreement until the Company is in compliance with the net borrowing base formula as defined in the Bank One credit facility agreement, at which time interest will only be paid in cash.
Under the amended Veritas Note, a principal payment of $500,000 was made on July 19, 2000, the effective date of the amendment, and another $500,000 payment was made in December 2000. The balance due Veritas was $3.7 million at December 31, 2000 with the entire balance classified as long-term in the accompanying financial statements.
Any additional proceeds derived from the exercise of warrants issued or from other debt or equity transactions must be used to pay interest and principal on the amended Veritas Note until paid in full. Effective November 1, 2000, Veritas exercised 500,000 warrants to receive 496,923 shares (net of exercise price) of Company common stock.
In connection with the closing of the AHC property acquisition on February 9, 1998, the Company issued a non-interest bearing note payable to AHC (the "AHC Note"). The Company had obtained a six-month extension of the $1.0 million payment due AHC from February 2000 to August 2000. This payment was made on August 3, 2000. Also, the $1.5 million payment due February 2001 has been divided into three quarterly installments of $500,000 each, payable commencing February 2001. A substantial portion of the first quarter 2001 payment was made in December 2000.
The Company's long-term debt consisted of the following as of December 31, 2000 and 1999 (in thousands):
(8) Capital Transactions and Common Stock Warrants
Capital Transactions
On July 11, 2000, the Company entered into a Securities Purchase Agreement (the "Securities Purchase Agreement") with Guardian. Pursuant to the Securities Purchase Agreement, the Company issued to Guardian a convertible promissory note in the amount of $5.0 million, and three warrants exercisable, for 1,562,500, 2,500,000 and 9,000,000 shares of the Company's Common Stock, respectively. Conversion of the note and exercise of the warrants were subject to stockholder approval, which was obtained at a stockholder meeting on December 7, 2000. Until the stockholders approved the conversion of the note, the Company accrued interest at an amount equal to the prime rate plus 10% per annum (or 19.5%). The accrual of interest is required under Emerging Issues Task Force ("EITF") 85-17 even though no interest is owed on this note since the stockholders approved the conversion of the note. Accordingly, the Company has incurred approximately $0.4 million of interest expense during the year ended December 31, 2000.
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Under current accounting pronouncements, in determining the beneficial conversion feature of the Guardian convertible note, the Company was required to assume that the fair value of the Guardian transaction was the closing price of the Company's common stock on the commitment date (July 11, 2000) which was the date the agreements were signed ($1.56 per share) versus the value agreed to by both parties of $1.35 per share using various valuation methodologies. The difference between these values of $.21 per share resulted in a non-cash charge to interest expense of $0.8 million on the date of stockholder approval of the note conversion. Also, the Company was required to use a value of $1.56 per share of Company Common Stock to allocate value to the warrants issued to Guardian. This also resulted in a non-cash charge to interest expense of $0.5 million, making a total of $1.3 million charge to interest expense related to valuation of the Guardian Transaction. These charges to interest expense are the result of using a prescribed fair value for our stock in accounting for these transactions which may not represent the actual value of the Guardian Transaction.
On July 11, 2000, the Company also signed a letter agreement (the "Eagle Transaction") to acquire an interest in certain undeveloped oil and gas properties and $0.5 million in cash from Eagle an affiliated entity controlled by C. E. Miller, the Chairman of the Company, in exchange for a total of 1,851,851 shares of common stock. In addition, Eagle was issued warrants exercisable for a total of 2,031,250 shares of common stock. Consummation of this transaction with Eagle was approved by the stockholders at a meeting on December 7, 2000.
Also on July 11, 2000, the Company also entered into a Subscription Agreement with ECCO Investments, LLC ("ECCO"), pursuant to which ECCO purchased 370,370 shares of the Company's common stock for an aggregate purchase price of $0.5 million or $1.35 per share.
Common Stock Warrants
At December 31, 2000, the Company has the following Common Stock Warrants outstanding:
(9) Financial Instruments
The following methods and assumptions were used to estimate the fair value of each significant class of financial instruments:
Cash, Restricted Cash, Temporary Cash Investments, Accounts Receivables, Accounts Payable and Notes Payable
The carrying amount approximates fair value because of the short maturity of those instruments.
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Long-Term Debt
The interest rate on the Credit Facility is reset as Bank One's prime rate changes to reflect current market rates. Consequently, the carrying value of the credit facility approximates fair value.
Hedging Arrangements
Refer to Note 10 for a description of the Company's price hedging arrangements and the fair values of the arrangements.
(10) Risk Management Activities and Derivative Transactions
The Company uses a variety of derivative instruments to manage exposure to fluctuations in commodity prices and interest rates. To qualify for hedge accounting, derivatives must meet the following criteria: (i) the item to be hedged exposes the Company to price or interest rate risk; and (ii) the derivative reduces that exposure and is designated as a hedge.
Commodity Price Hedges
The Company periodically enters into certain derivatives (e.g., NYMEX futures contracts) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce the exposure to price fluctuations. The Company's hedging arrangements apply to only a portion of its production, provide only partial price protection against declines in oil and natural gas prices and limit potential gains from future increases in prices. Such hedging arrangements may expose the Company to risk of financial loss in certain circumstances, including instances where production is less than expected, the Company's customers fail to purchase contracted quantities of oil or natural gas or a sudden unexpected event materially impacts oil or natural gas prices. For financial reporting purposes, gains and losses related to hedging are recognized as oil and natural gas revenues during the period the hedge transactions occur. The Company expects that the amount of hedge contracts that it has in place will vary from time to time. For the years ended December 31, 2000, 1999, and 1998, the Company hedged 54%, 45%, and 36% of its oil and gas production, respectively, and as of December 31, 2000, the
Company had 2.0 Bcfe of open oil and natural gas contracts for the months of January 2001 through December 2001. If all of these open contracts had been settled on December 31, 2000, the Company would have had to pay approximately $5.7 million as of December 31, 2000 to settle those contracts.
(11) Commitments and Contingencies
Leasing Arrangements
The Company leases its office building in Traverse City, Michigan from a related party. The lease term is for five years beginning in 1998 and contains an annual 4% escalation clause. In November 2000, the Company sub-leased approximately 1,500 square feet of its office space to an unrelated third party for one year. The Company also leases office space in Houston, Texas; Jackson, Mississippi; and Columbia, Mississippi; as well as warehouse space in Columbia, Mississippi. The lease agreements in Houston and Jackson were signed by the Company in September 1997 and April 1998, respectively. Each lease has a five year term. The lease for office and warehouse space in Columbia was assumed through the purchase of certain oil and gas properties from AHC in February 1998, as more fully discussed in Note 1. The Columbia lease term ends in June 2001.
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Future minimum lease payments required of the Company for years ending December 31, are as follows (in thousands):
Total net rent expense under these lease arrangements was $261,990, $255,078 and $198,547 for the years ended December 31, 2000, 1999 and 1998 respectively.
Employee Benefit Plan
The Company has a qualified 401(k) savings plan (the "Plan") covering substantially all eligible employees. The Plan provides for discretionary matching contributions by the Company. Commencing in July 1998, matching contributions have been in the form of Company stock. Contributions charged against operations totaled $50,650, $189,421 and $66,359 for the years ended December 31, 2000, 1999 and 1998, respectively.
Tax Credit and Royalty Participation Programs
Various employees were eligible to participate in the Company's Tax Credit and Royalty Participation Programs, which were designed to provide incentive for certain key employees of the Company. Under the programs, the employees were entitled to receive cash payments from the Company, based on overriding royalty working interests, fees, reimbursements and other financial items. These payments to the employees, which were charged against operations, totaled $54,611 for the year ended December 31, 1998. These programs were terminated upon the consummation of the Offering in February 1998.
Other
The Company has been named as a defendant in a lawsuit filed June 1, 1999 by Energy Drilling Company ("Energy Drilling"), in the Parish of Catahoula, Louisiana arising from a blowout of the Victor P. Vegas #1 well that was drilled and operated by the Company. Energy Drilling, the drilling rig contractor on the well, is claiming damages related to their destroyed drilling rig and related costs amounting to approximately $1.2 million, plus interest, attorneys' fees and costs. In January 2001, the District Court judge ruled against the Company on two of the three claims filed in this case with damages left undetermined. This ruling is being appealed to the U.S. Fifth Circuit Court of Appeals. In the event the Company does not prevail in the appeal, any resulting damages owed would be completely covered by insurance.
The Company has been named in a lawsuit brought by Victor P. Vegas, the landowner of the surface location of the blowout well referenced above. The suit was filed July 20, 1999 in the Parish of Orleans, Louisiana, claiming unspecified damages related to environmental and other matters.
The Company has been named in a lawsuit brought by Charles Strictland, employee of BJ Services, Inc., on September 30, 1999. The suit claimed damages of $1.0 million for personal injuries allegedly suffered at a well site operated by the Company. The judge ruled in favor of the Company at the trial held March 8, 2001.
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The Company had been named among several co-defendants in a lawsuit brought by Eric Parkinson, husband and personal representative of the Estate of Kelly Anne Parkinson (deceased). The amended complaint was filed December 13, 1999, in the County of Hillsdale, Michigan, claiming an unspecified amount plus interest and attorney fees for suffering the loss of the deceased care, comfort, society and support. Kelly Anne Parkinson was killed in an automobile accident on February 2, 1999, while traveling on a county road located next to land wherein the Company is lessee of underground mineral rights. The plaintiff alleged that the accident was the result of mud dragged on the road from the leased property and alleged that the Company was negligent in its duty to conduct its operations at the site with reasonable care. This case was settled and all claims dismissed in February 2001. All defense costs and the settlement amount will be covered by the Company's insurance.
The Company believes it has meritorious defenses to the claims discussed above and intends to vigorously defend these lawsuits. The Company does not believe that the final outcome of these matters will have a material adverse effect on the Company's operating results, financial condition or liquidity. Due to the uncertainties inherent in litigation, however, no assurances can be given regarding the final outcome of each action. The Company currently believes any costs resulting from each of the lawsuits mentioned above would be covered by the Company's insurance.
(12) Stock-Based Compensation
During 1997, the Company adopted the Stock Option and Restricted Stock Plan of 1997 (the "1997 Plan"). The 1997 Plan primarily is used to grant stock options. However, the 1997 Plan permits grants of restricted stock and tax benefit rights if determined to be desirable to advance the purposes of the 1997 Plan. These stock options, restricted stock and tax benefit rights are collectively referred to as "Incentive Awards." Persons eligible to receive Incentive Awards under the 1997 Plan are directors, corporate officers and other full-time employees of the Company and its subsidiaries. A maximum of 1.9 million shares of Common Stock (subject to certain antidilution adjustments) are available for Incentive Awards under the 1997 Plan.
Upon consummation of the Offering in February 1998, a total of 577,350 stock options were granted by the Company to directors, corporate officers and other full-time employees of the Company, and 109,500 shares of restricted stock were granted to certain employees. Also in February 1998, the Company made a one- time grant of an aggregate of 272,500 stock options to certain officers pursuant to the terms of stock option agreements entered into between the Company and the officers.
The restricted stock vested at cumulative increments of one-half of the total number of restricted shares of Common Stock subject thereto, beginning on the first anniversary of the date of grant. Because the shares of restricted stock were subject to the risk of forfeiture during the vesting period, compensation expense was recognized over the two-year vesting period as the risk of forfeiture passed. In February 2000 and 1999, 43,500 and 66,000 shares, respectively, of restricted stock either vested or was forfeited, and the Company recognized compensation expense of approximately $0.1 million and $0.2 million, respectively, in each of those years.
During 2000, 1999 and 1998, total incentive stock options of 473,500, 28,000 and 914,950, respectively, were issued to outside directors and employees under the 1997 Plan. Stock options totaling 1,224,950 of the 1,416,450 options issued over the past three years have been granted at the closing market prices on the date of grant so no compensation cost has been recognized for these stock options.
On January 1, 2000, the Company granted 191,500 stock options to certain employees with an exercise price of $0.01 per share. The right to exercise the options shall vest and be exercisable when the normal trading
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
average of the stock on the market remains above the designated values for a period of five consecutive trading days as follows:
When it is probable that the five-day stock price target will be attained (the "measurement date"), the Company will recognize compensation expense for the differences between the quoted market price of the stock at this measurement date less the $0.01 per share grant price times the number of options that will vest. Management does not currently believe it is probable that any of these targets will be attained during 2001, so no compensation expense has been recorded yet for these options.
On October 31, 2000, the Company granted 250,000 stock options to employees with an exercise price of $1.625 per share (the closing market price on the date of grant). The right to exercise the options shall vest at a rate of one- fifth per year beginning on the first anniversary of the grant date.
The Company accounts for all stock options issued under the provisions and related interpretations of Accounting Principles Board Opinion ("APB") No. 25, "Accounting for Stock Issued to Employees." In accordance with SFAS No. 123, "Accounting for Stock-Based Compensation," the Company intends to continue to apply APB No. 25 for purposes of determining net income and to present the pro forma disclosures required by SFAS No. 123.
The status of the restricted stock and stock options granted under the Stock Option and Restricted Stock Plan of 1997 is as follows:
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The average fair value of shares granted during 2000, 1999 and 1998 was $0.95, $1.68, and $4.10, respectively. The fair value of each option grant is estimated using the Black-Scholes option-pricing model with the following weighted-average assumptions used for estimating fair value:
The following table summarizes certain information for the options outstanding at December 31, 2000:
The Company's pro forma net loss and earnings (loss) per share of common stock had compensation costs been recorded in accordance with SFAS No. 123, are presented below (in thousands except per share data):
The effects of applying SFAS No. 123 in this pro forma disclosure should not be interpreted as being indicative of future effects.
(13) Related Party Transactions
In July 1996, the Company sold the building it occupies to C. E. Miller (Chairman of the Company's Board) and subsequently leased a substantial portion of the building under the terms of a five-year lease agreement. The lease was renegotiated in 1998 for a five-year term to increase the square footage being leased. (See Note 11). The Company realized a gain on the sale of the property of approximately $160,000. This gain was deferred and is being amortized in proportion to the gross rental charges under the operating lease.
Until March 1999, the Company provided technical and administrative services to Eagle. In connection with this arrangement, $66,667 and $200,000 were recognized as management fee income (see Note 16) for the years ended December 31, 1999 and 1998, respectively.
During 1999, Eagle purchased a working interest in certain unproved oil and gas properties from the Company for $3.9 million. The Company believes that the purchase price was representative of the fair market value of these interests and that the terms were consistent with those available to unrelated parties. The Company re-purchased certain of these properties in 2000 from Eagle, as more fully described in Note 8.
(14) Concentrations of Risk
The Company extends credit to various companies in the oil and gas industry in the normal course of business. Within this industry, certain concentrations of credit risk exist. The Company, in its role as operator of
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
co-owned properties, assumes responsibility for payment to vendors for goods and services related to joint operations and extends credit to co-owners of these properties.
This concentration of credit risk may be similarly affected by changes in economic or other conditions and may, accordingly, impact the Company's overall credit risk. The Company periodically monitors its customers' and co-owners' financial conditions.
The Company also has a significant concentration of properties in the Mississippi Salt Basin, which are affected by changes in economic and other conditions, including but not limited to crude oil and natural gas prices and operating costs.
(15) Non-Cash Activities
In December 2000, the Company issued 1,481,481 shares of common stock and 2,031,250 warrants to Eagle in exchange for certain non-producing oil and gas properties valued for financial reporting purposes at $2.6 million, as more fully described in Note 8. Also, the Company recorded $1.7 million of non-cash interest expense relating to the Guardian Convertible Promissory Note and the issuance of common stock warrants to Guardian, as more fully described in Note 8.
The Company issued 162,969 and 38,479 shares of common stock to its directors during the year ended December 31, 2000 and 1999, respectively as compensation as provided for under the Equity Compensation Plan for Non- employee Directors. The Company issued 49,539 and 48,178 shares of common stock to the Company's 401(k) Savings Plan during the year ended December 31, 2000 and 1999, respectively, the Company's matching contribution to the Plan.
In 1999, the Company reclassified approximately $1.5 from deferred revenue to capitalized oil and gas property costs as more fully discussed in Note 6. During 1998, the Company recorded a one-time non-cash charge of approximately $5.4 million for the termination of MOC's S corporation status, as discussed in Note 4; acquired certain oil and gas properties owned by non-affiliated parties for approximately $12.8 million of its Common Stock, as discussed in Note 1; and converted an accounts payable balance of $3.8 million into a note payable, as discussed in Note 7.
(16) Other Operating Revenues
The majority of the other operating revenues are reimbursements for general and administrative activities that the Company performs on behalf of partners and investors in jointly owned oil and gas properties. All other management fees that were earned for exploration and development activities have been credited against oil and gas property costs.
(17) Significant Customers
Revenues from certain customers accounted for more than 10% of total crude oil and natural gas sales as follows:
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(18) Supplemental Financial Information on Oil and Gas Exploration, Development and Production Activities (Unaudited)
The following information was prepared in accordance with the Supplemental Disclosure Requirements of SFAS No. 69, "Disclosures About Oil and Gas Producing Activities."
Users of this information should be aware that the process of estimating quantities of "proved" and "proved developed" crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir also may change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.
Proved reserves represent estimated quantities of natural gas and crude oil that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made.
Proved developed reserves are proved reserves expected to be recovered, through wells and equipment in place and under operating methods being utilized at the time the estimates were made.
The following estimates of proved reserves and future net cash flows as of December 31, 2000, 1999 and 1998 have been prepared by Miller and Lents, Ltd. (as to non-Michigan Antrim Shale reserves) and as of December 31, 1998 by S.A. Holditch and Associates (as to Michigan Antrim Shale reserves), independent petroleum engineers. All of the Company's reserves are located in the United States.
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Estimated Quantities of Proved Oil and Gas Reserves
The following table sets forth the Company's net proved and proved developed reserves at December 31 for each of the three years in the period ended December 31, 2000, and the changes in the net proved reserves for each of the three years in the period then ended as estimated by petroleum engineers for the respective periods as described in the preceding paragraph:
The following table summarizes the average year-end prices used to estimate reserves in accordance with SEC guidelines.
Standardized Measure of Discounted Future Net Cash Flows Relating To Proved Oil and Gas Reserves
The following information has been developed utilizing procedures prescribed by SFAS No. 69 and based on crude oil and natural gas reserve and production volumes estimated by the Company's petroleum engineers. It may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The future cash flows presented below are computed by applying year-end and prices to year-end quantities of proved crude oil and natural gas reserves. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the Company's proved reserves based on year-end costs and assuming continuation of existing economic conditions. It is expected that material revisions to some estimates of crude oil and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed and actual prices realized and costs incurred may vary significantly from those used.
Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.
The following table sets forth the Standardized Measure of Discounted Future Net Cash Flows from projected production of the Company's crude oil and natural gas reserves at December 31, 2000, 1999 and 1998:
- -------- (1) Crude oil and natural gas revenues are based on year-end prices with adjustments for changes reflected in existing contracts. There is no consideration for future discoveries or risks associated with future production of proved reserves. (2) Based on economic conditions at year-end. Does not include administrative, general or financing costs. Does not consider future changes in development or production costs. (3) The 1999 and 1998 balance is not reduced by income taxes due to the tax basis of the properties and a net operating loss carryforward. (4) The 2000 balance was computed using year end prices that were significantly higher than historical levels. Using a price of $5.02 per Mcfe which represents the February 2001 period ending prices, the standardized measure would be $57.2 million.
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Changes in Standardized Measure of Discounted Future Net Cash Flows
The following table sets forth the changes in the Standardized Measure of Discounted Future Net Cash Flows at December 31, 2000, 1999 and 1998:
Capitalized Cost Related to Oil and Gas Producing Activities
The following table sets forth the capitalized costs relating to the Company's natural gas and crude oil producing activities at December 31, 2000 and 1999:
Cost Incurred In Oil and Gas Producing Activities
The acquisition, exploration and development costs disclosed in the following tables are in accordance with definitions in SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Exploration costs include exploration expenses, additions to exploration wells in progress and depreciation of support equipment used in exploration activities. Development costs include additions to production facilities and equipment, additions to development wells in progress and related facilities and depreciation of support equipment and related facilities used in development activities.
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The following table sets forth costs incurred related to the Company's oil and gas activities for the years ended December 31:
- -------- (1) Includes $19,556 in 1998 for the acquisition of proved producing properties. (2) Includes $2,624 in 2000 of non-cash, non-producing properties acquired from Eagle as more fully described in Note 8. Includes $12,770 in 1998 of non-cash of proved producing and unproved properties acquired in connection with the Combination Transaction as more fully described in Note 1.
Results of Operations From Oil and Gas Producing Activities
The following table sets forth the Company's results of operations from oil and gas producing activities for the years ended December 31, 2000, 1999 and 1998. The results of operations below do not include general and administrative expenses, income taxes and interest expense.
MILLER EXPLORATION COMPANY
SUPPLEMENTAL QUARTERLY FINANCIAL DATA
Unaudited Quarterly Financial Information
In the opinion of the Company, the preceding quarterly information includes all necessary adjustments necessary for a fair statement of the results of operations for such periods. Earnings per share for each quarter are calculated based upon the weighted average number of shares outstanding during each quarter. As a result, adding the earnings per share for each quarter of a year may not equal annual earnings per share due to changes in shares outstanding thoughout the year.