-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, PitktnTTJkPyA9guoCsp8N6C4k0j+WtQ95Ml/saafcK/sc7r2roq6GryGGegPfSh fFxQ7ynvuOKCfyKv4kXiZg== 0001170918-04-000767.txt : 20041216 0001170918-04-000767.hdr.sgml : 20041216 20041216162724 ACCESSION NUMBER: 0001170918-04-000767 CONFORMED SUBMISSION TYPE: 10KSB/A PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20031231 FILED AS OF DATE: 20041216 DATE AS OF CHANGE: 20041216 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NATIONAL COAL CORP CENTRAL INDEX KEY: 0001089575 STANDARD INDUSTRIAL CLASSIFICATION: BITUMINOUS COAL & LIGNITE MINING [1220] IRS NUMBER: 650601272 STATE OF INCORPORATION: FL FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10KSB/A SEC ACT: 1934 Act SEC FILE NUMBER: 000-26509 FILM NUMBER: 041208606 BUSINESS ADDRESS: STREET 1: 8915 GEORGE WILLIAMS ROAD CITY: KNOXVILLE STATE: TN ZIP: 37923 BUSINESS PHONE: 8656906900 MAIL ADDRESS: STREET 1: 8915 GEORGE WILLIAMS ROAD CITY: KNOXVILLE STATE: TN ZIP: 37923 FORMER COMPANY: FORMER CONFORMED NAME: SOUTHERN GROUP INTERNATIONAL INC DATE OF NAME CHANGE: 19990625 10KSB/A 1 ncc10k03a3.txt SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-KSB/A Amendment No. 3 [X] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 2003 [ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Commission File Number 0-26509 ---------------------------------------------- NATIONAL COAL CORPORATION ---------------------------------------------- (Exact name of small business issuer as specified in its charter) SOUTHERN GROUP INTERNATIONAL, INC. ---------------------------------------------------------- (Former name) Florida 65-0601272 - ------------------------------- ------------------------ (State or other jurisdiction of (IRS Employer ID Number) incorporation or organization) 8913 George Williams Road, Knoxville, TN 37923 ---------------------------------------------- (Address of principal executive offices) (865) 690-6900 Issuer's Telephone Number --------------------------------------------------- (Former name, former address and former fiscal year, if changed since last report) INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS REQUIRED TO BE FILED BY SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS), AND (2) HAS BEEN SUBJECT TO SUCH FILING REQUIREMENTS FOR THE PAST 90 DAYS. Yes: [X] No: [_] As of March 23, 2004, the issuer had 42,552,162 shares of common stock, par value $.0001 per share issued and outstanding. EXPLANATORY NOTE We are filing this Annual Report on Form 10-KSB/A for the year ended December 31, 2003 (the "Amended Annual Report"), to amend our Annual Report on Form 10-KSB for the year ended December 31, 2003 (the "Original Annual Report"), which was originally filed with the Securities and Exchange Commission (the "SEC") on March 29, 2003, and amended by our Form 10-KSB/A filed March 31, 2004, and our Form 10-KSB/A filed December 10, 2004. The Company is filing this Amended Annual Report in response to comments received from the SEC. The Amended Annual Report revises Item 8a "Controls and Procedures," to clarify management's conclusions related to its evaluation of our disclosure controls and procedures. Unless otherwise stated, all information contained in this Amended Annual Report is as of March 31, 2004. TABLE OF CONTENTS PART I PAGE - ------ ---- Item 1. Description of Business 1 Item 2. Description of Property 23 Item 3. Legal Proceedings 24 Item 4. Submission of Matters to a Vote of Security Holders 24 PART II - ------- Item 5. Market for Common Equity and Related Stockholder Matters 25 Item 6. Management's Discussion and Analysis or Plan of Operation 26 Item 7. Financial Statements 44 Item 8. Changes in and Disagreements With Accountants on Accounting 45 and Financial Disclosure Item 8a. Controls and Procedures 45 PART III - -------- Item 9. Directors, Executive Officers, Promoters and Control Persons; Compliance with Section 16(a) of the Exchange Act 46 Item 10. Executive Compensation 48 Item 11. Security Ownership of Certain Beneficial Owners and Management 49 Item 12. Certain Relationships and Related Transactions 50 Item 13. Exhibits and Reports on Form 8-K 52 Item 14. Principal Accountant Fees and Services 52 SIGNATURES 54 PART I Item 1. Description of Business CORPORATE OVERVIEW Southern Group International, Inc. was incorporated in the State of Florida on August 10, 1995, and was inactive until 2003. On March 28, 2003, National Coal Corporation, a Tennessee corporation, entered into a Share Purchase Agreement whereby it purchased 500,000 shares of Southern Group International, Inc., a Florida corporation, from Surinder Rametra. Such shares were cancelled and returned to the treasury of Southern Group International, Inc. as of April 11, 2003. On April 11, 2003, the Board of Southern Group International, Inc. approved a Plan and Agreement of Reorganization whereby all the outstanding shares of National Coal Corporation (Tennessee) were exchanged on April 30, 2003 for 34,200,000 shares of Southern Group International, Inc. After the transaction, Jon Nix, Farrald Belote, Jr., Charles Kite, and Jeanne Bowen, or their designees, the principal owners of National Coal Corporation (Tennessee) prior to the reorganization, owned a total of 30,700,000 shares of Southern Group International, Inc. Articles of Amendment to the Articles of Incorporation were filed with the Florida Secretary of State's Office on August 4, 2003 changing the name of Southern Group International, Inc. to National Coal Corporation ("National Coal" or the "Company" hereafter). National Coal Corporation (Tennessee) operates as a wholly owned subsidiary of National Coal Corporation, a Florida corporation. The Company trades on the "Pink Sheets" under the symbol "NLCP.PK." The Company engages in coal production by locating, assembling, acquiring or leasing, assessing, permitting and developing coal properties in Eastern Tennessee in the Central Appalachian coal region. The Company, after obtaining permits from the Department of the Interior, mines said properties, or contracts with independent mine operators, for extraction of the coal minerals on a negotiated fee basis. Some contracts may be on a per ton basis, and some may be on a cost plus basis. The variance is usually due to varying extraction conditions and circumstances. The principal activity of the Company is coal mining. The Company currently owns, in fee simple, the coal mineral rights to the New River Tract assemblage, which consists of approximately sixty-five thousand (65,000) acres that lie in Anderson, Campbell and Scott Counties, approximately twenty-five miles northwest of Knoxville, Tennessee. These mineral rights revert back to the surface owner on June 5, 2093. At the present time there are two separate areas located on the New River Tract assemblage that are producing coal which include (1) a surface mine situated in Devonia, Tennessee (Patterson Mountain), and (2) a portion of the New River Tract mined by U.S. Coal, Inc., an independent mine operator that pays royalties to the Company on coal production. The Company currently sells its production into the spot market or sells coal based on short-term contracts, but in the future intends to seek long-term supply contracts. No such long-term contracts have been negotiated to date. Many of the Company's properties have been subject to limited production in the past. Some of the properties were abandoned by previous producers due to poor market conditions, uneconomical production, high labor costs and/or reclamation bond difficulties. Reclamation bonds are obtained and maintained by the Company for each producing property. Bonds typically take the form of cash deposits with the U.S. Department of the Interior, Office of Surface Mining. In theory, insurance bonds could be used, but such are extremely difficult and time consuming for small companies to obtain in the market. -1- The Company maintains an umbrella liability insurance policy for all of its operations, and requires liability policies to be furnished by contract operators, naming the Company as a co-insured. The coal industry has been highly competitive with very thin margins in recent years. Only in the past two years, in the opinion of management, have the economics begun to look favorable to coal again. This situation is due to, among other things, the surge in prices of natural gas. The price increases of natural gas, on a Btu basis, have reached the point that coal fired power plants, using the latest clean air compliant scrubber technology, can be price competitive with natural gas fired plants. The Company intends to exploit its mineral rights by opening mines, as its capital will allow, but it can only open a mine with an estimated $500,000 to $750,000 per mine, including bonds or cash deposited. Due to the operating capital constraints, if the Company cannot raise such needed additional amounts by loans or private placements, it will prevent the Company from expanding its mining operations beyond the current operations. GLOSSARY OF SELECTED TERMS Anthracite. The highest rank of economically usable coal with moisture content less than 15% by weight and heating value as high as 15,000 Btu per pound. It is jet black with a high luster. It is mined primarily in Pennsylvania. Appalachia. The coal producing states of Alabama, Georgia, eastern Kentucky, Maryland, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia and West Virginia. Ash. The impurities consisting of iron, alumina and other incombustible matter contained in coal. Since ash increases the weight of coal, it adds to the cost of handling and can affect the burning characteristics of coal. Assigned Reserves. The coal that is committed to be mined at operating facilities. Bituminous Coal. The most common type of coal with moisture content less than 20% by weight and heating value of 10,500 to 14,000 Btu per pound. It is dense and black and often has well-defined bands of bright and dull material. British Thermal Unit or "Btu." A measure of the thermal energy required to raise the temperature of one pound of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit). Clean Air Act Amendments of 1990. A comprehensive set of amendments to the federal law governing the nation's air quality. The Clean Air Act was originally passed in 1970 to address significant air pollution problems in our cities. The 1990 amendments broadened and strengthened the original law to address specific problems such as acid deposition, urban smog, hazardous air pollutants and stratospheric ozone depletion. Coal Seam. Coal deposits occur in layers. Each layer is called a "seam." Coke. A hard, dry carbon substance produced by heating coal to a very high temperature in the absence of air. Coke is used in the manufacture of iron and steel. Its production results in a number of useful byproducts. Coking Coal. Coal used to make coke and interchangeably referred to as metallurgical coal. Compliance Coal. The coal having a sulfur dioxide content of 1.2 pounds or less per million Btu, as required by Phase II of the Clean Air Act. -2- Continuous Mining. A form of underground, room-and-pillar mining that uses a continuous mining machine to cut coal from the seam and load it onto conveyors or into shuttle cars in a continuous operation. Deep Mine. An underground coal mine. Dragline. A large excavating machine used in the surface mining process to remove overburden. Dragline Mining. A form of mining where large capacity, electric-powered draglines remove overburden to expose the coal seam. Smaller shovels load coal in haul trucks for transportation to the preparation plant and then to the rail loadout. Fossil Fuel. Fuel such as coal, petroleum or natural gas formed from the fossil remains of organic material. Highwall Mining. A technique of using a continuous mining machine under robotic remote control to mine coal from underground. Illinois Basin. The coal producing area in Illinois, southern Indiana and western Kentucky. Lignite. The lowest rank of coal, which contains a high moisture content of up to 45% by weight and heating value of 6,500 to 8,300 Btu per pound. It is brownish black and tends to oxidize and disintegrate when exposed to air. Longwall Mining. A form of underground mining in which a panel or block of coal, generally at least 700 feet wide and often over one mile long, is completely extracted. The working area is protected by a moveable, powered roof support system. Metallurgical Coal. Various grades of coal suitable for carbonization to make coke for steel manufacture. Also known as "met" coal, it possesses four important qualities: volatility, which affects coke yield; the level of impurities, which affects coke quality; composition, which affects coke strength; and basic characteristics, which affect coke oven safety. Met coal has a particularly high Btu, but low ash content. Nitrogen Oxide (NOx). A gas formed in high temperature environments such as coal combustion. It is a harmful pollutant that contributes to acid rain. Non-Compliance Coal. The coal having a sulfur dioxide content of more than 1.2 pounds per million Btu. Overburden. The Layers of earth and rock covering a coal seam. In surface mining operations, overburden is removed prior to coal extraction. Overburden Ratio/Stripping Ratio. The amount of overburden that must be removed compared to a given quantity of coal. It is commonly expressed in cubic yards per ton of coal or as a ratio comparing the thickness of the overburden with the thickness of the coal bed. Pillar. An area of coal left to support the overlying strata in a mine. Pillars are sometimes left permanently to support surface structures. Powder River Basin. The coal producing area in northeastern Wyoming and southeastern Montana. This is the largest known source of coal reserves and the largest producing region in the United States. Preparation Plant. A coal processing facility, usually located on a mine site, although one plant may serve several mines. A preparation plant is a facility for crushing, sizing and washing coal to prepare it for use by a particular customer. The washing process has the added benefit of removing some of the coal's sulfur content. -3- Probable Reserves. Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less appropriately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation. Proven Reserves. Reserves for which: (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes with grade and/or quality computed from the results of detailed sampling, and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established. Reclamation. A process of restoring land and the environment to an approved state following mining activities. The process commonly includes "recontouring" or reshaping the land to its approximate original appearance, restoring topsoil and planting native grass and ground covers. Reclamation operations are usually underway before the mining of a particular site is completed. Reclamation is closely regulated by both state and federal law. Reserve. That part of a mineral deposit that could be economically and legally extracted or produced at the time of the reserve determination. Roof. A stratum of rock or other mineral above a coal seam or the overhead surface of an underground coal working place. Same as "back" or "top." Room-and-Pillar Mining. The most common method of underground mining in which the mine roof is supported mainly by coal pillars left at regular intervals. Rooms are placed where the coal is mined; pillars are areas of coal left between the rooms. Room-and-pillar mining is done either by conventional or continuous mining. Scrubber (flue gas desulfurization unit). Any of several forms of chemical/physical devices which operate to neutralize sulfur compounds formed during coal combustion. These devices combine the sulfur in gaseous emissions with other chemicals to form inert compounds, such as gypsum, that must then be removed for disposal. Although effective in substantially reducing sulfur from combustion gases, scrubbers require about 6% to 7% of a power plant's electrical output and thousands of gallons of water to operate. Steam Coal. Coal used by power plants and industrial steam boilers to produce electricity or process steam. It generally is lower in Btu heat content and higher in volatile matter than metallurgical coal. Sub-Bituminous Coal. A dull, black coal that ranks between lignite and bituminous coal. Its moisture content is between 20% and 30% by weight, and its heat content ranges from 7,800 to 9,500 Btu per pound of coal. Sulfur. One of the elements present in varying quantities in coal that contributes to environmental degradation when coal is burned. Sulfur dioxide is produced as a gaseous by-product of coal combustion. Sulfur Content. Coal is commonly classified by its sulfur content due to the importance of sulfur in environmental regulations. "Low sulfur" coal has a variety of definitions but typically is used as a classification for coal containing 1.0% or less sulfur. Surface Mine. A coal mine in which the coal lies near the surface and can be extracted by removing the covering layer of soil (see "Overburden"). About 60% of total U.S. coal production comes from surface mines. Ton. A "short" or net ton is equal to 2,000 pounds. A "long" or British ton is 2,240 pounds; a "metric" ton is approximately 2,205 pounds. The short ton is the unit of measure referred to in this document. -4- Truck-and-Shovel Mining. A form of mining where large shovels are used to remove overburden, which is used to backfill pits after the coal is removed. Smaller shovels load coal in haul trucks for transportation to the preparation plant or rail loading facility. Unassigned Reserves. Coal at inactive locations and coal that has not been committed, and that would require new mine development, mining equipment or plant facilities before operations could begin on the property. Underground Mine. Also known as a "deep" mine. Usually located several hundred feet below the earth's surface, an underground mine's coal is removed mechanically and transferred by shuttle car or conveyor to the surface. Most underground mines are located east of the Mississippi River and account for about 40% of annual U.S. coal production. Unit Train. A train of 100 or more cars carrying only coal. A typical unit train can carry at least 10,000 tons of coal in a single shipment. Western Bituminous Coal Regions. The coal producing area including, the Hanna Basin in Wyoming, the Uinta Basin of northwestern Colorado and Utah, the Four Corners Region in New Mexico and Arizona and the Raton Basin in southern Colorado. COAL INDUSTRY OVERVIEW The Company obtained the information provided in this "Coal Industry Overview" regarding future coal production and consumption and future electricity generation from the Energy Information Administration, the International Energy Agency, the National Mining Association, Energy Ventures Analysis, Inc., Resource Data International, Inc. and the National Energy Technology Laboratory. The Energy Information Administration is the independent statistical and analytical agency within the U.S. Department of Energy. The International Energy Agency is an autonomous agency linked with the Organization for Economic Cooperation and Development whose member countries cooperate in the development of rational energy programs. The National Mining Association is a national trade organization that represents the interests of mining before Congress, the Administration, federal agencies, the judiciary and the media. Energy Ventures Analysis, Inc. and Resource Data International, Inc. are private market research firms. The National Energy Technology Laboratory is an agency of the U.S. Department of Energy. For the definitions of certain technical terms used in this document, please refer to "Glossary of Terms." The Energy Information Administration, the primary source of the data, bases its forecasts on assumptions about, among other things, trends in various economic sectors (residential, transportation, industrial, etc.), economic growth rates, technological improvements and demand for other energy sources. The Energy Information Administration's Annual Energy Outlook 2003 and International Energy Outlook 2002 more fully describe these assumptions. The other sources noted herein do not describe the assumptions upon which they base their projections. Introduction Coal is one of the world's most abundant, efficient and affordable natural resources, and is used primarily as fuel for the generation of electricity. According to the International Energy Agency, in 2000, coal provided 26% of the world's primary energy supply and was responsible for approximately 39% of the world's power generation. Coal's share of electricity generation in the United States was estimated at 50% in 2002. As the table below indicates, coal fueled more electricity in the United States in 2001 than all other fuels combined. -5- Electricity Fuel Sources (based on net generation) 1990 1995 2001 2002 ---- ---- ---- ---- Coal 52.5% 51.0% 50.9% 50.2% Nuclear 19.0 20.1 20.6 20.3 Hydro 9.6 9.3 5.8 6.9 Natural Gas 12.3 14.8 17.1 17.9 Other 6.6 4.8 5.6 4.7 ----- ----- ----- ----- Total 100% 100% 100% 100% Source: Energy Information Administration Monthly Energy Review, April 2003. The United States is the second largest coal producer in the world, exceeded only by China. Other leading coal producers include Australia, India and South Africa. The United States has the largest coal reserves in the world, with an estimated 250 years of supply based on current usage rates. U.S. coal reserves are more plentiful than U.S. oil or natural gas reserves, with coal representing more than 85% of the nation's fossil fuel reserves. U.S. coal production has nearly doubled during the past 30 years. In 2002, total U.S. coal production was estimated to be 1.1 billion tons. Approximately 66% of U.S. coal is produced by surface mining methods, while the remaining 34% is produced by underground mining methods. The U.S. coal industry operates under a highly developed regulatory regime that governs all mining and mine safety activities, including land reclamation, which requires mined lands to be restored to a condition equal to or better than that existing before mining. Coal mining in the United States has become a relatively safe occupation, relying on sophisticated technology and a skilled work force to become one of the safest, most productive industries in the world. In recent years, the coal industry has experienced significant gains in mining productivity, changes in air quality laws, growth in coal consumption and industry consolidation. According to the Energy Information Administration, the number of operating mines declined 52% over the past 10 years, while overall coal production increased approximately 8% over that period. During the same period, average coal mine productivity nearly doubled due to changes in work practices, new technologies and an increase in production in the Powder River Basin coal region, where thick, easily accessible coal seams result in high productivity. The overall productivity gains contributed to stability in coal prices during the 1990s. Recent increases in the price of natural gas and other energy commodities, however, have resulted in the price of coal increasing in most regions where the Company operates. A notable industry trend has been the shift to low sulfur coal production, particularly in the Powder River Basin, driven by the significant regulatory restrictions on sulfur dioxide emissions from coal-fueled electric generating plants. Coal Markets The Energy Information Administration estimates that approximately 1.1 billion tons of coal were consumed in the United States in 2002 and expects domestic consumption of coal by electric generators to grow at an annual rate of 1.4% per year from 2001 through 2025, predicated on natural gas price assumptions of $2.88 per million Btu in 2005 and $3.30 in 2010. Demand from domestic electric generators accounts for more than 90% of domestic coal consumption. The Energy Information Administration projects annual coal use growth by electric generators of nearly 400 million tons by 2025. -6- U.S. Coal Consumption by Sector Coal-fueled generation is used in most cases to meet baseload requirements, so coal use generally grows at the pace of electricity growth. Gas-fired electric generation, which is used primarily for intermediate and peak-load demand, is anticipated to gain market share at the expense of nuclear generation or where peak-load capacity is needed. Sources of Coal Demand Growth In the aggregate, coal-fueled plants currently utilize approximately 70% of their capacity, although the optimal sustainable capacity utilization is estimated at 85% for a typical plant, and most plants can run at higher rates for short periods. An increase from 70% capacity utilization to 85% capacity utilization would translate into approximately 200 million tons of additional annual coal consumption. In addition to expected greater utilization of existing plants, a number of new coal-fueled generating plants have been announced in recent years to meet America's needs for inexpensive baseload generating capacity. Regional Coal Markets Over the past several years, largely as a result of sulfur dioxide emissions limitations mandated by the Clean Air Act, demand has shifted toward lower sulfur coal. In 1995, Phase I of the Clean Air Act required high sulfur coal plants to reduce their emissions of sulfur dioxide to 2.5 pounds or less of sulfur dioxide per million Btu. As a result of a significant switch to very low sulfur Powder River Basin coal, many Phase I-affected plants over complied with the sulfur dioxide requirements, creating a surplus of emission allowances that could be traded within a market for sulfur dioxide emissions credits. In 2000, Phase II of the Clean Air Act tightened restrictions on sulfur dioxide emissions from 2.5 pounds or less to 1.2 pounds or less of sulfur dioxide per million Btu. Surplus emission credits from Phase I allowed some generators to delay retrofitting old plants with scrubbers. Eventually, owners of these plants will have to retrofit or switch to Phase II compliance coal, including Powder River Basin or other low sulfur coal. The following table indicates that the ongoing shift to Powder River Basin coal is expected to continue. U.S. Coal Production by Supply Region (in million tons) Historical Projected
2001 2005 2010 2015 2020 ---- ---- ---- ---- ---- Powder River Basin 408 410 509 563 632 Central/Southern Appalachia 290 272 286 286 280 Northern Appalachia 143 131 124 120 128 Illinois Basin 95 103 102 104 107 Other Western US 103 99 104 117 118 Lignite 91 101 96 88 86 Other 9 9 9 8 8 ----- ----- ----- ----- ----- Total 1,139 1,125 1,230 1,286 1,359
Source: Energy Information Administration, Annual Energy Outlook 2003. -7- Coal Characteristics There are four types of coal: lignite, subbituminous, bituminous and anthracite. Each has characteristics that make it more or less suitable for different end uses. In general, coal of all geological composition is characterized by end use as either "steam coal" or "metallurgical coal," sometimes known as "met coal." Steam coal is used by electricity generators and by industrial facilities to produce steam, electricity or both. Metallurgical coal is refined into coking coal, which is used in the production of steel. Heat value and sulfur content, the most important coal characteristics, determine the best end use of particular types of coal. Heat Value The heat value of coal is commonly measured in Btu per pound of coal. Coal found in the eastern and midwestern regions of the United States tends to have a heat content ranging from 10,000 to 15,000 Btu per pound. Most coal found in the western United States ranges from 8,000 to 10,000 Btu per pound. The weight of moisture in coal, as sold, is included in references to Btu per pound of coal in this document, unless otherwise indicated. Lignite is a brownish-black coal with a heat content that generally ranges from 4,500 to 8,500 Btu per pound. Major lignite operations are located in Louisiana, Montana, North Dakota and Texas. Lignite is used almost exclusively in power plants located adjacent to or near these mines because any transportation costs, coupled with mining costs, would render its use uneconomical. The Company does not have any lignite reserves. Subbituminous coal is a black coal with a heat content that ranges from 8,000 to 12,000 Btu per pound. Most subbituminous reserves are located in Alaska, Colorado, Montana, New Mexico, Washington and Wyoming. Subbituminous coal is used almost exclusively by electric generators and some industrial consumers. Bituminous coal is a "soft" black coal with a heat content that ranges from 9,500 to 15,000 Btu per pound. This coal is located primarily in Appalachia, Arizona, the Midwest, Colorado and Utah, and is the type most commonly used for electric generation in the United States. Bituminous coal is also used for industrial steam purposes and is used in steel production. Anthracite is a "hard" coal with a heat content that can be as high as 15,000 Btu per pound. A limited amount of anthracite deposits is located primarily in the Appalachian region of Pennsylvania. Anthracite is used primarily for industrial and home heating purposes. The Company does not have any anthracite reserves. Sulfur Content Sulfur content can vary from seam to seam and sometimes within each seam. Coal combustion produces sulfur dioxide, the amount of which varies depending on the chemical composition and the concentration of sulfur in the coal. Low sulfur coal has a variety of definitions, and in this document "low sulfur" is referred to coal with sulfur content of 1.0% or less by weight. Compliance coal refers to coal with a sulfur content of less than 1.2 pounds per million Btu. The strict emissions standards of the Clean Air Act have increased demand for low sulfur coal. The Company expects continued high demand for low sulfur coal as electric generators meet the current Phase II requirements of the Clean Air Act (1.2 pounds or less of sulfur dioxide per million Btu). U.S. sulfur dioxide emissions from electricity generation have decreased 30% from 1990 to 2000 levels, while coal consumed by U.S. electric generators has increased 26% during the same period. Subbituminous coal typically has a lower sulfur content than bituminous coal, but some bituminous coal in Colorado, eastern Kentucky, Tennessee, southern West Virginia and Utah also has a low sulfur content. -8- Plants equipped with sulfur-reduction technology, known as "scrubbers," which reduce sulfur dioxide emissions by 50% to 95%, can use higher sulfur coal. Plants without scrubbers can use medium and high sulfur coal by purchasing emission allowances on the open market or blending that coal with low sulfur coal. Each allowance permits the user to emit a ton of sulfur dioxide. Some older coal-fueled plants have been retrofitted with scrubbers. Any new coal-fueled generation built in the United States will likely use clean coal technologies to remove the majority of sulfur dioxide, nitrogen oxide and particulate matter emissions. Other Ash is the inorganic residue remaining after the combustion of coal. As with sulfur content, ash content varies from seam to seam. Ash content is an important characteristic of coal because electric generating plants must handle and dispose of ash following combustion. Moisture content of coal varies by the type of coal, the region where it is mined and the location of coal within a seam. In general, high moisture content decreases the heat value and increases the weight of the coal, thereby making it more expensive to transport. Moisture content in coal, as sold, can range from approximately 5% to 30% of the coal's weight. When some types of coal are super-heated in the absence of oxygen, they form a hard, dry, caking form of coal called coke. Steel production uses coke as a fuel and reducing agent to smelt iron ore in a blast furnace. Coal Mining Techniques Coal mining operations commonly use four distinct techniques to extract coal from the ground. The most appropriate technique is determined by coal seam characteristics such as location and recoverable reserve base. Drill hole data are used initially to define the size, depth and quality of the coal reserve area before committing to a specific extraction technique. All coal-mining techniques rely heavily on technology; consequently, technological improvements have resulted in increased productivity. The four most common mining techniques are (1) continuous mining, (2) longwall mining, (3) truck-and-shovel mining and (4) dragline mining. It is generally easier to mine coal seams that are thick and located close to the surface than thin underground seams. Typically, coal-mining operations will begin at the part of the coal seam that is easiest and most economical to mine. In the coal industry, this characteristic is referred to as "low ratio." As the seam is mined, it becomes more difficult and expensive to mine because the seam either becomes thinner or protrudes more deeply into the earth, requiring removal of more material over the seam, known as the "overburden." For example, many seams of coal in the Midwest are five to 10 feet thick and located hundreds of feet below the surface. In contrast, seams in the Powder River Basin of Wyoming may be 80 feet thick and located only 50 feet below the surface. Once the raw coal is mined, it is often crushed, sized and washed in preparation plants where the product consistency and heat content are improved. This process involves crushing the coal to the required size, removing impurities and, where necessary, blending it with other coal to match customer specifications. Continuous Mining Continuous mining is an underground mining method in which main airways and transportation entries are developed and remote-controlled continuous miners extract coal from "rooms," leaving "pillars" to support the roof. Shuttle cars transport coal from the face to a conveyor belt for transport to the surface. This method is often used to mine smaller coal blocks or thin seams, and seam recovery is typically approximately 50%. Productivity for continuous mining averages 25 to 50 tons per miner shift. -9- Longwall Mining Longwall mining is an underground mining method that uses hydraulic jacks or shields, varying from five feet to 12 feet in height, to support the roof of the mine while a mobile-cutting sheerer advances through the coal. Chain belts then move the coal to a standard deep mine conveyer system for delivery to the surface. Continuous mining is used to develop access to long rectangular panels of coal, which are then mined with longwall equipment, allowing controlled subsidence behind the advancing machinery. Longwall mining is highly productive, but it is effective only for large blocks of medium to thick coal seams. High capital costs associated with longwall mining demand a large, contiguous reserve base. Seam recovery using longwall mining is typically 70%, and productivity averages 40 to 80 tons per miner shift. Truck-and-Shovel Mining Truck-and-shovel mining is an open-cast method that uses large electric-powered shovels to remove overburden, which is used to backfill pits after coal removal. Shovels load coal in haul trucks for transportation to the preparation plant or rail loadout. Seam recovery using the truck-and-shovel method is typically 90%. Productivity depends on equipment, geological composition and the ratio of overburden to coal. Productivity varies between 250 to 400 tons per miner shift in the Powder River Basin to 30 to 80 tons per miner shift in eastern U.S. regions. Dragline Mining Dragline mining is an open-cast method that uses large capacity electric-powered draglines to remove overburden to expose the coal seams. Shovels load coal in haul trucks for transportation to the preparation plant and then to the rail loadout. Truck capacity can range from 80 to 400 tons per load. Seam recovery using the dragline method is typically 90% or more, and productivity levels are similar to those for truck-and-shovel mining. Technology Coal mining technology is continually evolving and improving, among other things, underground mining systems and larger earth-moving equipment for surface mines. For example, longwall mining technology has increased the average recovery of coal from large blocks of underground coal from 50% to 70%. At larger surface mines, haul trucks have capacities of 240 to 400 tons, which is nearly double the maximum capacity of the largest haul trucks used a decade ago. This increase in capacity, along with larger shovels and draglines, has increased overall mine productivity. According to National Mining Association data, overall coal mine productivity, measured in tons produced per miner shift, increased 85% from 1990 to 2001. Coal Regions Coal is mined from coalfields throughout the United States, with the major production centers located in the Powder River Basin, Central Appalachia, Northern Appalachia, the Illinois Basin and in other western coalfields. The Company operates in the Central Appalachia region. Powder River Basin The Powder River Basin contains some of the largest coal reserves in the world. The Powder River Basin covers more than 12,000 square miles in northeastern Wyoming and 7,000 square miles in southeastern Montana. Demonstrated coal reserves total approximately 188 billion tons. Within the Powder River Basin, there are various qualities of subbituminous coal, with current production of subbituminous coal ranging from 8,300 Btu per pound to 9,200 Btu per pound and from 0.8% sulfur to 0.2% sulfur. The mines located just north and south of Gillette, Wyoming are categorized as Southern Powder River Basin mines. The coal in the Southern Powder River Basin is ranked as subbituminous with an extremely low sulfur content. -10- Production in the Southern Powder River Basin has increased from approximately seven million tons in 1970 to approximately 360 million tons in 2002, and coal production in the Powder River Basin now accounts for approximately 30% of U.S. coal consumption by volume. The Southern Powder River Basin has grown into the largest coal supply region in the United States. From 1990 to 2000, the region's compounded annual production growth rate was 7% compared to an overall compounded annual production growth rate of 0.5% for the total U.S. coal industry. The Southern Powder River Basin markets more than 95% of its coal to U.S. electricity generators, principally in this region between the Rocky Mountains and the Appalachian Mountains. Central / Southern Appalachia Central/Southern Appalachia contains coalfields in eastern Kentucky, Tennessee, Alabama, southwestern Virginia and central and southern West Virginia. Production in Central/Southern Appalachia has decreased from approximately 305 million tons in 1996 to approximately 290 million tons in 2001. Production declined in all major sections of Central/Southern Appalachia except for southern West Virginia, which has grown due to the expansion of more economically attractive surface mines. The region has experienced significant consolidation in the past several years due to modest demand growth and strong competition from western coal. Central/Southern Appalachian operators market approximately 67% of their coal to electric generators, principally in the southeastern United States. Central/Southern Appalachia also sells extensively to the export market and industrial customers. The coal of Central/Southern Appalachia has an average heat content of 12,500 Btu per pound and generally has low sulfur content. Northern Appalachia High and medium sulfur coal is found in the Northern Appalachian coalfields of western Pennsylvania, southeastern Ohio and northern West Virginia. Demand for coal from this region has in recent years been and is expected to remain relatively stable. Production in the region was approximately 143 million tons in 2001. Much of the production in this region is concentrated in a few highly productive longwall mining operations in southeastern Pennsylvania and northern West Virginia. Despite its sulfur content of 1.5% to 2.0%, which is considered medium sulfur coal, coal from the Pittsburgh seam produced from these mines is considered attractive to electricity generators because of its high heat content of approximately 13,000 Btu per pound. Illinois Basin The Illinois Basin consists of approximately 48,000 square miles throughout Illinois, southern Indiana and western Kentucky. There has been significant consolidation among coal producers in the Illinois Basin over the past several years. Production in the Illinois Basin peaked at 141 million tons in 1990. Since 1990 and until recently, production had decreased by over 33% due to displacement by lower sulfur, lower-cost coal. However, recently, production in the Illinois Basin has stabilized. Illinois Basin coal is sold primarily to local customers. Demonstrated reserves total an estimated 135 billion tons of bituminous coal. Approximately 16 coal seams have been identified in this region. Current production quality ranges from 9,000 to 12,700 Btu per pound and 0.8% to 4.5% sulfur, with production averaging approximately 11,400 Btu per pound and 2.5% sulfur. Western Bituminous Coal Regions The western bituminous coal regions include the Uinta Basin of northwestern Colorado and Utah, the Four Corners Region in New Mexico and Arizona and the Raton Basin in southern Colorado. These regions produce high-quality, low sulfur steam coal for selected markets in these regions, for export through west coast ports and for shipment to some midwestern customers. Production in these regions has decreased from 104 million tons in 1996 to 103 million tons in 2001. -11- Lignite Production Regions Lignite is mined in Louisiana, Montana, North Dakota and Texas. Coal Prices Coal prices vary dramatically by region and are determined by a number of factors. The two principal components of the delivered price of coal are the price of coal at the mine, which is influenced by mine operating costs and coal quality, and the cost of transporting coal from the mine to the point of use. Electric generators purchase coal on the basis of its delivered cost per million Btu. Price at the Mine The price of coal at the mine is influenced by geological characteristics such as seam thickness, overburden ratios and depth of underground reserves. Eastern U.S. coal is more expensive to mine than western coal, because of thinner coal seams and thicker overburden. Underground mining, prevalent in the eastern United States, has higher labor costs than surface mining, including costs for labor benefits and health care, and high capital costs, including modern mining equipment and construction of extensive ventilation systems. In addition to the cost of mine operations, the price of coal at the mine is also a function of quality characteristics such as heat value and sulfur, ash and moisture content. Metallurgical coal has higher carbon and lower ash content and is usually priced $4 to $10 per ton higher than steam coal produced in the same regions. Higher prices are paid for special coking coal with low volatility characteristics. Transportation Costs Coal used for domestic consumption is generally sold freight on board (FOB) at the mine, as described above, and the purchaser normally bears the transportation costs. Export coal, however, is usually sold at the loading port, and coal producers are responsible for shipment to the export coal-loading facility and the buyer pays the ocean freight. Most electric generators arrange long-term shipping contracts with rail or barge companies to assure stable delivered costs. Transportation can be a large component of the buyer's cost. Although the customer pays the freight, transportation cost is still important to coal mining companies because the customer may choose a supplier largely based on the cost of transportation. According to the National Mining Association, railroads account for nearly two-thirds of total U.S. coal shipments. Trucks and overland conveyors haul coal over shorter distances, while lake carriers and ocean vessels move coal to export markets. Some domestic coal is shipped over the Great Lakes. Most coal mines are served by a single rail company, but much of the Powder River Basin is served by two competing rail carriers. Cost of Electricity Generation Cost Comparison of Fuel Types Coal prices at the mine, and transportation costs together constitute coal's delivered price to customers. Coal attained its leading market share because of its relative low cost and its availability throughout the United States. The cost of fuel is the largest variable cost involved in electricity generation. The delivered cost of coal to electric generators is relatively stable as compared to the cost of natural gas and oil. -12- Generating Costs In addition to fuel, electric generators incur other variable and fixed costs in electricity production. On average, the total cost per megawatt-hour of coal-fueled electricity generation is less expensive than for electricity generated from natural gas or nuclear power. According to Resource Data International Inc., 20 of the 25 major electric generation plants with the lowest operating costs in the United States in 2001 were coal-fueled. Hydroelectric power is inexpensive but is limited geographically, and there are few suitable sites for new hydroelectric dams. Moreover, because coal-fueled electric generating plants, on average, are operating below maximum capacity, these plants can increase their electricity generation without substantial incremental capital costs, thus improving coal's overall cost competitiveness. The following table illustrates the average cost of coal-fueled generation relative to other electric generating sources. Deregulation of the Electricity Generation Industry Congress enacted the Energy Policy Act of 1992 to stimulate competition in electricity markets by giving wholesale suppliers access to the transmission lines of U.S. electricity generators. In April 1996, the Federal Energy Regulatory Commission (FERC) issued the first of a series of orders establishing rules providing for open access to electricity transmission systems. The federal government is currently exploring a number of options concerning utility deregulation. Some individual states are also proceeding with their own deregulation initiatives. The pace of deregulation differs significantly from state to state. As of December 2002, 17 states and the District of Columbia had either enacted legislation leading to the deregulation of the electricity market or issued a regulatory order to implement retail access that would allow customers to choose their own supplier of generation. Five states have delayed restructuring and 27 are not actively pursuing deregulation. In California, where supply and demand imbalances created electricity supply shortages, the California Public Utilities Commission suspended deregulation. A possible consequence of deregulation is downward pressure on fuel prices. However, because of coal's cost advantage and because some coal-fueled generating facilities are underutilized in the current regulated electricity market, the Company believes that additional coal demand would arise as electricity markets are deregulated if the most efficient coal-fueled power plants are operated at greater capacity. COMPANY OPERATIONS The Company is currently mining coal on a portion of its' New River Tract. The Company has no long-term supply contracts at this time, and is selling coal on the spot market, as well as through short-term contracts. The Company is seeking to enter into long-term contracts, but there is no guarantee that such contracts will be secured. The Company will need substantial additional capital to support its' budget. The Company has a limited operating history and only began coal mining activities in August 2003 when it commenced production from its mine # 2 surface mine. Areas of Interest The New River Tract assemblage of coal mineral rights owned by the Company consists of approximately sixty-five thousand (65,000) acres that lie in Anderson, Campbell and Scott Counties, Tennessee. -13- There are six coal seams that are known to contain mineable coal, that exceed twenty-eight inches in thickness under these mineral rights. The coal seams that are twenty-eight inches in thickness or larger are virgin or have been partially mined over the last hundred plus years on the New River Tract. Several additional coal seams, which outcrop near the top of the mountains, have been partially surfaced mined, but because of the limited amount of information available, no determination of mineability can be made for these seams. The Sewanee and Bon Air coal seams are present under the mineral rights but lie more than a thousand feet below drainage. At the present time there are two separate areas located on the New River Tract assemblage that are producing coal which include (1) a surface mine situated in Devonia, Tennessee (Patterson Mountain), and (2) a portion of the New River Tract mined by U.S. Coal, Inc., an independent mine operator that pays royalties to the Company on coal production. The Company is currently working on four additional permits to open mines and has been the process with the Office of Surface Mining. Location The Company's New River Tract mineral rights assemblage is located approximately twenty-five miles northwest of Knoxville, Tennessee. Portions of the mineral rights extend into Anderson, Campbell and Scott Counties, Tennessee. Transportation Transportation facilities in the area of these mineral rights include roads and rail. The road network includes Tennessee State Highway 116, which crosses the mineral rights and several gravel and hard surface roads that provide adequate access for any mining operations. Interstate Highways 75 and 40 are within a few miles of the property. All of the rail facilities are served by the Norfolk Southern Railroad. In addition, there are two Tennessee Valley Authority ("TVA") coal-fired steam plants within thirty miles of the area. The TVA-Kingston steam plant and the TVA-Bull Run plant are located on good, hard surface roads that are adequate for delivery of coal by truck. Drilling Information Several mining companies have performed core drilling in the area. Over seven hundred core holes are either located on the mineral rights property or are close enough to the mineral rights property to provide reference information. Geology Known coal bearing strata on the property include coal beds from the Crab Orchard and Crooked Fork groups, and the Slatestone, Indian Bluff, Graves Gap, Red Oak Mountain, Vowell Mountain and Cross Mountain formations. Only coal seams from the Blue Gem coal, located near the top of the Slatestone formation, upwards occur on the New River Tract. Core drilling has indicated the existence of coal as low as the Wilder coals, at the top of the Gizzard Group. The strata that are above the water drainage level consist mainly of relatively thick shale and siltstone sequences with sandstone layers. Coal seams occur in the shale sequences. There are six coal seams that are targets and all of these seams are above the water drainage level. There are other coal seams that contain coal, but insufficient information is available to estimate mineability. The northern portion of the New River Tract property has not been explored by core drilling, and could possibly contain a large amount of coal. -14- Railroad Loading Facilities There are railroad facilities located at Devonia, Tennessee, where Tennessee Mining, Inc. (a division of Addington Enterprises, Inc.) was active until the spring of 1998. Also railroad facilities are available at Smoky Junction, Tennessee, where U.S. Coal, Inc. is presently operating one underground mine on the Pewee Rider coal seam on Burge Mountain. A coal processing facility is located at each of the above railroad facilities. The Company, subject to availability of funds, intends to improve rail facilities where necessary to serve its production needs. COAL SEAM DESCRIPTION ON COMPANY MINERAL RIGHTS IN TENNESSEE NOTE: The Company cannot now compute any "reserves" because only two of its' properties are in a state of production. "Reserves", to be so classified, must be based upon reasonably accurate scientific data and professional analysis, be recoverable (economically and physically), have a permitted and operating mine facility at the coal location, and be subject to current sales. All of these criteria have not been met on the Company's mineral rights. The Company has, however, estimated potential tonnages in its' mineral rights, based upon information available to it and professional reports by a qualified professional geologist for internal use only. Such internal tonnage estimates should not be viewed as reserves because of the lack of criteria compliance discussed above. The use of "potential coal" or "potential tons" is theoretical and assumes both existence and mineability, of which there is no assurance. Jellico Seam The Jellico (State) seam is located near the base of the Jellico Formation in the Pennsylvanian Series. The elevation of the coal, in the Coon Pool Branch area, is approximately 1550 feet. The rock strata dips to the northwest at 0.5 to 1.0 percent. Topographic relief is relatively high (1800 to 1900 feet) with base drainage levels of 1400 to 1500 feet elevation and mountain tops as high as 3350' in elevation. The area is drained by Coon Pool Branch, which flows east into the New River. Eleven core holes were drilled in the area, with ten of the holes showing coal of mineable thickness. The area consists of 514 acres of mineable coal, of which 496 acres are considered measured and has 2,377,500 tons (in place) with an additional 81,000 tons in the indicated category. West Coal Company, which mined the area in the early 1980's and prior to Tennessee Mining, Inc., drilled the eleven drill holes, but no coal quality analyses are available. Tennessee Mining, Inc. operated mines in the area from 1995 to early 1998, but did no core drilling in the area. The Jellico seam coal has been mined extensively on the Company's property, including the Stallion Branch mine immediately to the west of the area. The sulfur content of past samples of coal from the Jellico seam ranged from 1.5 to 2.5%. It is unknown to what extent any of this coal is a mineable. Core drilling was done in this area by West Coal Company, which mined the Jellico seam on Cages Creek and on Smoky Creek, an area that lies west of the area mined by the Company. Windrock Seam The Windrock coal seam is the uppermost unit of the Graves Gap group, and it lies approximately four hundred feet above the Jellico coal seam. Several mines have operated this seam in Anderson and Campbell Counties, Tennessee, but none on the New River Tract. The area contains 1,632 acres with the potential for 7,834,704 tons based on information from more than eighty core holes that were drilled by West Coal Company and Tennessee Mining, Inc.; however no mining was done by either company, although a permit has been approved for underground mining on Buffalo Mountain. It is unknown to what extent any of this is mineable coal. -15- Big Mary Seam The Big Mary (Dean) seam lies approximately fifty feet above the Windrock coal seam. Four areas are considered to contain mineable coal. This coal is in the lower portion of the Red Oak Mountain Group. Three underground mines that operated on the property show the following sulfur content. o Moore mine at Devonia - sample taken in 1953 - 4.1% sulfur o Trimore mine at Devonia - sample taken in 1953 - 3.2% sulfur o Alrosha mine on Bootjack Mt. - sample taken in 1976 - 2.5% sulfur The area on High Point contains 567 acres and 2,721,600 tons of potential coal and another 42 acres with 201,600 tons of potential coal. The core drilling in the area was done by West Coal Company in the 1980's. Tennessee Mining, Inc. did not drill core holes that penetrated this seam in the area. High Point Mountain contains 395 acres and 2,133,000 tons of potential coal and another 120 acres with 648,000 tons of potential coal. Only one core hole has been drilled on this seam on High Point Mountain. The hole was drilled by West Coal Company in the 1980's. The potentials were based on measurements along the coal seam outcrop line where the coal was exposed. Tennessee Mining, Inc. did not drill this area. Ash Log Mountain contains 593 acres and 3,024,300 potential tons and another 83 acres with 423,300 potential tons of coal. Two core holes have been drilled on the area, however a large potion of the outcrop line has been surface mined, which indicates the coal is of mineable thickness. The outcrop line measurements show thicker coal than the drill holes indicate. No quality analyses are available for this area. Tennessee Mining, Inc. did not drill this area. Red Oak Mountain contains 421 acres and 2,399,700 tons of potential coal and another 34 acres and 193,800 tons of potential coal. The core holes in this area were drilled by Koppers, Inc. and Anchor Oil Co. Tennessee Mining, Inc. drilled two holes in 1997 that are south of the area. Walnut Mountain Seam The Walnut Mountain seam lies approximately three hundred fifty feet above the Big Mary seam and forty feet below the Pewee seam. The coal is usually less than 1% sulfur and has a high Btu content. The area on High Point contains 193 acres and 864,500 tons of potential coal in the measured category. Several core holes have been drilled in the area. Tennessee Mining, Inc. drilled twenty-one holes, with West Coal Company and Conrich Coal drilling the remaining holes. The underground mine was mined by Scott Coal Corporation (owned by West Coal Co.), and closed in the mid 1980's. The area on Buffalo Mountain contains 624 acres and 3,369,600 tons of potential coal on the Walnut Mountain seam. More than thirty core holes have been drilled in the area. The coal seams have partings (shale zones) in some of the area and the coal will have to be processed (i.e. processed at a wash and prep plant) before it can be marketed. This area is above the Windrock area on Buffalo Mountain. Pewee Seam The area of the Pewee seam on Fork Mountain contains approximately 1,372,000 tons of potential coal on 286 acres that remains unmined. At present, a mine is permitted on this area. The mine can be re-opened in a short time - usually 60 to 90 days. The mine is permitted as Reatta Mining, Fork Mtn. Mine #1. -16- The coal seam averages thirty inches in thickness and is a "low sulfur product", with less than 1% sulfur content. The coal from the Pewee seam usually can be sold without washing if mining conditions are favorable. There is an area on Stallion Mountain where the Pewee seam averages 33" in thickness and has an area containing 486 acres and 2,405,700 tons of potential coal in the measured category. The top of Stallion Mountain possibly may allow mountain top surface mining. Pewee Rider Seam The area on the High Point property contains 139 acres and 771,500 tons of potential coal and another 8 acres and 44,400 tons of potential coal. The Pewee Rider seam lies approximately forty feet above the Pewee coal seam and eighty-five feet above the Walnut Mountain seam; however, in some areas the interval can be much less. Twenty-one core holes were drilled by Tennessee Mining, Inc. in 1995 on this seam. The area on the Hannah property contains 94 acres and 465,300 tons of potential coal. This area is adjacent to the Reatta Mining #3 mine, and should be underground mined. A surface mine is permitted and active to the north and adjacent to the area. ACREAGE AND COAL SEAMS FOUND IN THE NATIONAL COAL CORPORATION ASSEMBLAGE - NEW RIVER TRACT - ------------------------------------------------------------------------------ SEAM LOCATION MEASURED ACRES ====================== ========================== ==================== Jellico Coon Pool Branch 496 Jellico Cage Creek 1,230 Windrock Buffalo Mountain 1,632 Big Mary High Point 567 Big Mary High Point Mountain 395 Big Mary Ash Log Mountain 593 Big Mary Red Oak Mountain 421 Walnut Mt. High Point 193 Walnut Mt. Buffalo Mountain 624 Pewee Fork Mountain 286 Pewee Stallion Mountain 486 Pewee Rider High Point 139 Pewee Rider Burge Mountain 380 Pewee Rider Hannah Top 94 Backlog of Orders. There are currently various orders for sales at this time. - ----------------- Government Contracts. None at this time. - -------------------- -17- REGULATORY MATTERS Federal, state and local authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, the reclamation and restoration of mining properties after mining has been completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects of mining on groundwater quality and availability. In addition, the industry is affected by significant legislation mandating certain benefits for current and retired coal miners. Numerous federal, state and local governmental permits and approvals are required for mining operations. The Company believes that it has obtained all permits currently required to conduct its present mining operations. The Company may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that a proposed exploration for, or production of, coal may have on the environment. These requirements could prove costly and time-consuming, and could delay commencing or continuing exploration or production operations. Future legislation and administrative regulations may emphasize the protection of the environment and, as a consequence, the Company's activities may be more closely regulated. Such legislation and regulations, as well as future interpretations and more rigorous enforcement of existing laws, may require substantial increases in equipment and operating costs to the Company and delays, interruptions or a termination of operations, the extent of which cannot be predicted. The Company endeavors to conduct its mining operations in compliance with all applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time in the industry. None of the violations to date or the monetary penalties assessed upon the Company have been material. Mine Safety and Health Stringent health and safety standards have been in effect since Congress enacted the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and Health Act of 1977 significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. Most of the states, including the state of Tennessee in which the Company operates, have state programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the coal mining industry is perhaps the most comprehensive and pervasive system for protection of employee health and safety affecting any segment of U.S. industry. While regulation has a significant effect on operating costs of the Company, U.S. competitors of the Company are subject to the same degree of regulation. Environmental Laws The Company is subject to various federal, state and foreign environmental laws. Some of these laws, discussed below, place many requirements on coal mining operations. Federal and state regulations require regular monitoring of the Company's mines and other facilities to ensure compliance. Surface Mining Control and Reclamation Act The Surface Mining Control and Reclamation Act of 1977 (SMCRA), which is administered by the Department of the Interior's Office of Surface Mining Reclamation and Enforcement (OSM), establishes mining, environmental protection and reclamation standards for all aspects of surface mining as well as many aspects of deep mining. Mine operators must obtain SMCRA permits and permit renewals for mining operations from the OSM. Where state regulatory agencies have adopted federal mining programs under the act, the state becomes the regulatory authority. -18- SMCRA permit provisions include requirements for coal prospecting; mine plan development; topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; protection of the hydrologic balance; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; and re-vegetation. The mining permit application process is initiated by collecting baseline data to adequately characterize the pre-mine environmental condition of the permit area. This work includes surveys of cultural resources, soils, vegetation, wildlife, assessment of surface and ground water hydrology, climatology and wetlands. In conducting this work, the Company collects geologic data to define and model the soil and rock structures and coal that is to be mined. The Company develops mine and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. The mine and reclamation plan incorporates the provisions of SMCRA, the state programs and the complementary environmental programs that impact coal mining. Also included in the permit application are documents defining ownership and agreements pertaining to coal, minerals, oil and gas, water rights, rights of way and surface land and documents required of the OSM's Applicant Violator System. Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness review and technical review. Public notice of the proposed permit is given for a comment period before a permit can be issued. Some SMCRA mine permits take over a year to prepare, depending on the size and complexity of the mine and often take six months to two years to be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public has rights to comment on and otherwise engage in the permitting process, including through intervention in the courts. Before a SMCRA permit is issued, a mine operator must submit a bond or otherwise secure the performance of reclamation obligations. The Abandoned Mine Land Fund, which is part of SMCRA, requires a fee on all coal produced. The proceeds are used to reclaim mine lands closed prior to 1977 and to pay health care benefit costs of orphan beneficiaries of the Combined Fund. The fee, which partially expires on September 30, 2004, is $0.35 per ton on surface-mined coal and $0.15 per ton on deep-mined coal. After that date, a fee will be assessed each year to cover the expected health care benefit costs of the orphan beneficiaries. The Company is current on all Abandoned Mine Land Fund payments. SMCRA stipulates compliance with many other major environmental programs. These programs include the Clean Air Act; Clean Water Act; Resource Conservation and Recovery Act (RCRA); Comprehensive Environmental Response, Compensation, and Liability Acts (CERCLA) superfund and employee right-to-know provisions. Besides OSM, other Federal regulatory agencies are involved in monitoring or permitting specific aspects of mining operations. The U.S. Environmental Protection Agency (EPA) is the lead agency for States or Tribes with no authorized programs under the Clean Water Act, RCRA and CERCLA. The U.S. Army Corps of Engineers (COE) regulates activities affecting navigable waters and the U.S. Bureau of Alcohol, Tobacco and Firearms (ATF) regulates the use of explosive blasting. The Company does not believe there are any substantial matters that pose a risk to maintaining its existing mining permits or hinder its ability to acquire future mining permits. It is Company policy to comply with all requirements of the Surface Mining Control and Reclamation Act and the state laws and regulations governing mine reclamation. Clean Air Act The Clean Air Act, the Clean Air Act Amendments and the corresponding state laws that regulate the emissions of materials into the air, affect coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations may occur through Clean Air Act permitting requirements and/or emission control requirements relating to particulate matter, such as fugitive dust, including future regulation of fine particulate matter measuring 10 micrometers in diameter or smaller. The Clean Air Act indirectly affects coal mining operations by extensively regulating the air emissions of sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fueled electricity generating plants. -19- In July 1997, the EPA adopted new, more stringent National Ambient Air Quality Standards for very fine particulate matter and ozone. As a result, some states will be required to change their existing implementation plans to attain and maintain compliance with the new air quality standards. The Company's mining operations and electricity generating customers are likely to be directly affected when the revisions to the air quality standards are implemented by the states. State and federal regulations relating to implementation of the new air quality standards may restrict the Company's ability to develop new mines or could require the Company to modify its existing operations. The extent of the potential direct impact of the new air quality standards on the coal industry will depend on the policies and control strategies associated with the state implementation process under the Clean Air Act, but could have a material adverse effect on the Company's financial condition and results of operations. Title IV of the Clean Air Act Amendments places limits on sulfur dioxide emissions from electric power generation plants. The limits set baseline emission standards for these facilities. Reductions in emissions occurred in Phase I in 1995 and in Phase II in 2000 and apply to all coal-fueled power plants. The affected electricity generators have been able to meet these requirements by, among other ways, switching to lower sulfur fuels, installing pollution control devices, such as flue gas desulfurization systems, which are known as "scrubbers," reducing electricity generating levels or purchasing sulfur dioxide emission allowances. Emission sources receive these sulfur dioxide emission allowances, which can be traded or sold to allow other units to emit higher levels of sulfur dioxide. The Company cannot accurately predict the effect of these provisions of the Clean Air Act Amendments on it in future years. At this time, the Company believes that implementation of Phase II has resulted in an upward pressure on the price of lower sulfur coals, as additional coal-fueled electricity generating plants have complied with the restrictions of Title IV. The Clean Air Act Amendments also require electricity generators that currently are major sources of nitrogen oxides in moderate or higher ozone non-attainment areas to install reasonably available control technology for nitrogen oxides, which are precursors of ozone. In addition, the EPA promulgated the final rules that would require coal-burning power plants in 19 eastern states and Washington, D.C. to make substantial reductions in nitrogen oxide emissions beginning in May 2004. Installation of additional control measures required under the final rules will make it more costly to operate coal-fueled electricity generating plants. The Clean Air Act Amendments provisions for new source review require electricity generators to install the best available control technology if they make a major modification to a facility that results in an increase in its potential to emit regulated pollutants. From 1990 to 1999, the EPA interpreted the new source review criteria in a relatively consistent manner; however, the EPA changed their interpretation during 1999. The Justice Department, on behalf of the EPA, filed a number of lawsuits since November 1999, alleging that 10 electricity generators violated the new source review provisions of the Clean Air Act Amendments at power plants in the Midwestern and Southern United States. The EPA issued an administrative order alleging similar violations by the Tennessee Valley Authority, affecting seven plants and notices of violation for an additional eight plants owned by the affected electricity generators. Many electricity generators have announced settlements with the Justice Department requiring the installation of additional control equipment on selected generating units. If the remaining electricity generators are found to be in violation, they could be subject to civil penalties and be required to install the required control equipment or cease operations. The Company's customers are among the named electricity generators and if found not to be in compliance, or as a result of the settlements, the fines and requirements to install additional control equipment could adversely affect the amount of coal they would burn if the plant operating costs were to increase to the point that the plants were operated less frequently. At the end of 2002, the EPA issued proposed new source review rules for sources that include electricity generators. These new rules define routine maintenance, repair and replacement. If these rules are finalized without material revisions, electricity generators should be better able to make needed repairs and improvements to their plants without the uncertainty of triggering cost-prohibitive environmental rules. -20- The Clean Air Act Amendments set a national goal for the prevention of any future, and the remedying of any existing, impairment of visibility in 156 national parks and wildlife areas across the country. Under regulations issued by the EPA in 1999, states are required to set a goal of restoring natural visibility conditions in these Class I areas in their states by 2064 and to explain their reasons to the extent they determine that this goal cannot be met. The state plans may require the application of "Best Available Retrofit Technology" after 2010 on sources found to be contributing to visibility impairment of regional haze in these areas. The control technology requirements could cause customers of the Company to install equipment to control sulfur dioxide and nitrogen oxide emissions. The requirement to install control equipment could affect the amount of coal supplied to those customers if they decide to switch to other sources of fuel to lower emission of sulfur dioxides and nitrogen oxides, which may have a material adverse affect on the Company. The Clean Air Act Amendments require a study of electricity generating plant emissions of certain toxic substances, including mercury, and direct the EPA to regulate these substances, if warranted. In December 2000, the EPA decided that mercury air emissions from power plants should be regulated. The Company expects that the EPA will propose regulations in 2004 and will issue final regulations perhaps nine months thereafter. It is possible that future regulatory activity may seek to reduce mercury emissions and these requirements, if adopted, could result in reduced use of coal if electricity generators switch to other sources of fuel. In addition, Vice President Cheney, as the head of the National Energy Policy Development Group, submitted to the President a National Energy Policy which recommended, among other things, that the President direct the EPA Administrator to work with Congress to propose legislation that would significantly reduce and cap emissions of sulfur dioxide, nitrogen oxide and mercury from electricity power generators. In February 2002, the President proposed to cut electricity power generator emissions by approximately 70% by 2018 using a cap and trade system similar to that now in effect for acid deposition control. The President's proposal has been translated into a legislative proposal. In addition, similar emission reduction proposals have been introduced in Congress, some of which propose to regulate the three pollutants and carbon dioxide, but no such legislation has passed either house of the Congress. If this type of legislation were enacted into law, it could impact the amount of coal supplied to those electricity-generating customers if they decide to switch to other sources of fuel whose use would result in lower emission of sulfur dioxides, nitrogen oxides, mercury and carbon dioxide, all of which may have an adverse material affect on the Company. In February 2003, a number of states notified the EPA that they plan to sue the agency to force it to set new source performance standards for utility emissions of carbon dioxide and to tighten existing standards for sulfur dioxide and particulate matter for utility emissions. In June 2003, Massachusetts, Connecticut and Maine filed a lawsuit against the EPA seeking a court order requiring the EPA to designate carbon dioxide as a criteria pollutant. If these states are successful in obtaining a court order and the EPA agrees to set emission limitations for carbon dioxide, it could adversely affect the amount of coal customers would purchase from the Company. Clean Water Act The Clean Water Act of 1972 affects coal-mining operations by establishing in-stream water quality standards and treatment standards for wastewater discharge through the National Pollutant Discharge Elimination System (NPDES). Regular monitoring, reporting requirements and performance standards are requirements of NPDES permits that govern the discharge of pollutants into water. Total Maximum Daily Load (TMDL) regulations established a process by which states designate stream segments as impaired (not meeting present water quality standards). Industrial dischargers, including coal mines, will be required to meet new TMDL effluent standards for these stream segments. The adoption of new TMDL effluent limitations for the Company's coal mines could require more costly water treatment and could adversely affect coal production of the Company. -21- States are also adopting anti-degradation regulations in which a state designates certain water bodies or streams as "high quality." These regulations would prohibit the diminution of water quality in these streams. Waters discharged from coal mines to high quality streams will be required to meet or exceed new "high quality" standards. The designation of high quality streams at the Company's coal mines could require more costly water treatment and could aversely affect the Company's coal production. Resource Conservation and Recovery Act The Resource Conservation and Recovery Act (RCRA), which was enacted in 1976, affects coal mining operations by establishing requirements for the treatment, storage and disposal of hazardous wastes. Coal mine wastes, such as overburden and coal cleaning wastes, are exempted from hazardous waste management. Subtitle C of RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous. In a 1993 regulatory determination, the EPA addressed some high volume-low toxicity coal combustion wastes generated at electric utility and independent power producing facilities. In May 2000, the EPA concluded that coal combustion wastes do not warrant regulation as hazardous under RCRA. The EPA is retaining the hazardous waste exemption for these wastes. However, the EPA has determined that national non-hazardous waste regulations under RCRA Subtitle D are needed for coal combustion wastes disposed in surface impoundments and landfills and used as mine-fill. The agency also concluded beneficial uses of these wastes, other than for mine filling, pose no significant risk and no additional national regulations are needed. As long as this exemption remains in effect, it is not anticipated that regulation of coal combustion waste will have any material effect on the amount of coal used by electricity generators. Federal and State Superfund Statutes Superfund and similar state laws affect coal mining and hard rock operations by creating a liability for investigation and remediation in response to releases of hazardous substances into the environment and for damages to natural resources. Under Superfund, joint and several liabilities may be imposed on waste generators, site owners or operators and others regardless of fault. Global Climate Change The United States, Australia and more than 160 other nations are signatories to the 1992 Framework Convention on Climate Change, which is intended to limit emissions of greenhouse gases, such as carbon dioxide. In December 1997, in Kyoto, Japan, the signatories to the convention established a binding set of emission targets for developed nations. Although the specific emission targets vary from country to country, the United States would be required to reduce emissions to 93% of 1990 levels over a five-year budget period from 2008 through 2012. Although the United States has not ratified the emission targets and no comprehensive regulations focusing on greenhouse gas emissions are in place, these restrictions, whether through ratification of the emission targets or other efforts to stabilize or reduce greenhouse gas emissions, could adversely affect the price and demand for coal. According to the Energy Information Administration's Emissions of Greenhouse Gases in the United States 2001, coal accounts for 32% of greenhouse gas emissions in the United States, and efforts to control greenhouse gas emissions could result in reduced use of coal if electricity generators switch to lower carbon sources of fuel. In March 2001, President Bush reiterated his opposition to the Kyoto Protocol and further stated that he did not believe that the government should impose mandatory carbon dioxide emission reductions on power plants. In February 2002, President Bush announced a new approach to climate change, confirming the Administration's opposition to the Kyoto Protocol and proposing voluntary actions to reduce the greenhouse gas intensity of the United States. Greenhouse gas intensity measures the ratio of greenhouse gas emissions, such as carbon dioxide, to economic output. The President's climate change initiative calls for a reduction in greenhouse gas intensity over the next 10 years which is approximately equivalent to the reduction that has occurred over each of the past two decades. -22- Permitting Mining companies must obtain numerous permits that impose strict regulations on various environmental and safety matters in connection with coal mining. These provisions include requirements for coal prospecting; mine plan development; topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; protection of the hydrologic balance; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; and revegetation. The Company must obtain permits from applicable state regulatory authorities before it begins to mine reserves. The mining permit application process is initiated by collecting baseline data to adequately characterize the pre-mine environmental condition of the permit area. This work includes surveys of cultural resources, soils, vegetation, wildlife, assessment of surface and ground water hydrology, climatology and wetlands. In conducting this work, the Company collects geologic data to define and model the soil and rock structures and coal that will be mined. The Company develops mine and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. The mine and reclamation plan incorporates the provisions of the Surface Mining Control and Reclamation Act, the state programs and the complementary environmental programs that impact coal mining. Also included in the permit application are documents defining ownership and agreements pertaining to coal, minerals, oil and gas, water rights, rights of way, and surface land and documents required of the Office of Surface Mining's Applicant Violator System. Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness review, technical review and public notice and comment period before it can be approved. Some Surface Mining Control and Reclamation Act mine permits can take over a year to prepare, depending on the size and complexity of the mine and often take six months to sometimes two years to receive approval. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public has rights to comment on and otherwise engage in the permitting process, including through intervention in the courts. The Company does not believe there are any substantial matters that pose a risk to maintaining its existing mining permits or hinder its ability to acquire future mining permits (except availability of cash for bond deposits). It is the Company's policy to ensure that its operations are in full compliance with the requirements of the Surface Mining Control and Reclamation Act and the state laws and regulations governing mine reclamation. EMPLOYEES At December 31, 2003, the Company had 26 full-time employees, of which 20 were engaged in direct mining operations, 2 in mining supervision, and 4 in executive management and legal administration. None of the Company's employees are covered by a collective bargaining agreement. The Company considers its relationship with its employees to be favorable. The Company currently utilizes the services of 3 independent consultants: 1 in research, 1 in accounting, and 1 in security. The 20 miners and 2 supervisors are based in Devonia, Tennessee; the Chief Executive Officer/President, the Chief Financial Officer and the General Counsel are based in Knoxville, Tennessee. The Chairman is based in Houston, Texas. Item 2. Description of Properties The Company's executive offices are located at 319 Ebenezer Road, Knoxville, TN 37923; the telephone number is (865) 769-3749 and the facsimile number is (865) 769-3759. The Company leases corporate office space), at a monthly cost of $1,800, with a lease term which expires in September 2004. The Company's base of operations for its mining activities is located in Devonia, Tennessee. The Company also leases space outside Atlanta, Georgia on a month-to-month basis at a cost of $600 per month, to house its web servers and financial data computers. The Company also leases storage space in eastern Tennessee to house its maps and other geological data. -23- Item 3. Legal Proceedings The Company is not involved in any litigation. Item 4. Submission of Matters to a Vote of Security Holders None. -24- PART II Item 5. Market for Common Equity and Related Stockholder Matters Common Stock Our Common Stock trades in the Over The Counter market, through the quotation medium commonly referred to as the "Pink Sheets," under the symbol "NLCP.PK." The following table sets forth, for the periods indicated, the high and low sales prices for our Common Stock: High Low ------- -------- Year Ended December 31, 2002 First Quarter ......................... $ 0.60 $ 0.50 Second Quarter ........................ * * Third Quarter ......................... * * Fourth Quarter ........................ * * *There is no reliable information available for these quotes due to the inactivity of the stock during this period. High Low ------- -------- Year Ended December 31, 2003 First Quarter ......................... $ 0.60 $ 0.50 Second Quarter ........................ 0.60 0.50 Third Quarter ......................... 0.51 0.45 Fourth Quarter ........................ 0.51 0.35 On March 17, 2004, the closing sales price of the Common Stock as reported on the Pink Sheets was $1.28 per share. As of March 17, 2003, there were 89 holders of record of our Common Stock. Dividends We have never paid any dividends on our Common Stock. We intend to retain any earnings for use in our business and do not intend to pay any cash dividends on our Common Stock in the foreseeable future. Equity Compensation Plan Information The following table sets forth certain information regarding our equity compensation plans as of December 31, 2003.
Number of securities to Number of securities be issued upon exercise Weighted-average exercise remaining available for of outstanding warrants price of outstanding future issuance under equity and rights warrants and rights compensation plans - ----------------------- -------------------------- --------------------------- ---------------------------- Equity compensation plans not approved by shareholders 1,762,250 $ 0.5547 -- - ----------------------- -------------------------- --------------------------- ----------------------------
Material Features of Individual Equity Compensation Plans not Approved by Stockholders In March 2003, we issued to The Webb Group warrants to purchase up to 1,597,250 shares of our common stock at an exercise price of $0.55 per share as consideration for the issuance of two notes payable. At the time of issuance, this exercise price was at a premium to the price per share as quoted on the Pink Sheets. The warrants have a term of 2 years. These warrants were subsequently purchase by Crestview Capital Master, LLC directly from The Webb Group in February 2004. In November 2003, we issued to an unrelated third party warrants to purchase up to 45,833 shares of our common stock at an exercise price of $0.60 per share as consideration for the extension of the maturity date of a note payable. The warrants have a term of 2 years. In November 2003, we issued to an unrelated third party warrants to purchase up to 27,500 shares of our common stock at an exercise price of $0.60 per share as consideration for the extension of the maturity date of a note payable. The warrants have a term of 2 years. In November 2003, we issued to an unrelated third party warrants to purchase up to 41,667 shares of our common stock at an exercise price of $0.60 per share as consideration for the extension of the maturity date of a note payable. The warrants have a term of 2 years. In November 2003, we issued to an unrelated third party warrants to purchase up to 50,000 shares of our common stock at an exercise price of $0.60 per share as consideration for the extension of the maturity date of a note payable. The warrants have a term of 2 years. In March 2004, the Chairman agreed to reduce his annual base salary to $36,000. This agreement was entered into as a result of the Chairman taking a much less active role in the day-to-day operations of the Company. Concurrent with this reduction in annual base salary, the Chairman, who had been accruing his salary since October 2003, agreed to receive all previously accrued salary in stock, using a price per share of $0.55. This resulted in the issuance of 167,832 shares to the Chairman in March 2004. -25- Item 6. Management's Discussion and Analysis of Financial Condition and Results of Operations No operations were conducted and no operating revenue was realized from January 30, 2003 to June 30, 2003. From January 30, 2003 through June 30, 2003, the Company's activities consisted of strategic, organizational, property acquisition and financing matters. During the calendar third quarter 2003, production commenced and accordingly, the Company is no longer considered to be in the exploration stage. As of December 31, 2003, the Company was totally illiquid and needed cash infusions from shareholders to provide capital, or needed loans from any sources available. At December 31, 2003, the Company had negative working capital of approximately $5,512,000 and a stockholders' deficiency of approximately $2,927,000. These factors raise substantial doubt about the Company's ability to continue as a going concern. The principal activity of the Company is coal mining. The Company currently owns, in fee simple, the coal mineral rights to the New River Tract assemblage, which consists of approximately sixty-five thousand (65,000) acres that lie in Anderson, Campbell and Scott Counties, approximately twenty-five miles northwest of Knoxville, Tennessee. These mineral rights revert back to the surface owner on June 5, 2093. At the present time there are two separate areas located on the New River Tract assemblage that are producing coal which include (1) a surface mine situated in Devonia, Tennessee (Patterson Mountain), and (2) a portion of the New River Tract mined by U.S. Coal, Inc., an independent mine operator that pays royalties to the Company on its' coal production. The Company engages in coal production by locating, assembling, leasing, assessing, permitting and developing coal properties in Eastern Tennessee. The Company, after obtaining permits from the U.S. Department of the Interior, mines said properties or contracts with independent mine operators for extraction of the coal minerals on a negotiated fee basis. Some contracts may be on a per ton basis, and some may be on a cost plus basis. The variance is usually due to varying extraction conditions and circumstances. Reclamation bonds are obtained and maintained by the Company for each producing property. Bonds typically take the form of cash deposits with the U.S. Department of the Interior, Office of Surface Mining. In theory, insurance bonds could be used, but such are extremely difficult and time consuming for small companies to obtain in the market. The Company currently sells its' production into the spot market and/or based on short-term contracts, but in the future intends to seek long-term supply contracts. No such long-term contracts have been negotiated to date. Many of the Company's properties have been subject to limited production in the past. Some of the properties were abandoned by previous producers due to poor market conditions, uneconomical production, high labor costs and difficulty in securing reclamation bonds. The Company is required to obtain reclamation bonds for each producing property. Bonds typically take the form of cash deposits with the U.S. Department of the Interior, Office of Surface Mining. In theory, insurance bonds could be used, but such are extremely difficult and time consuming for small companies to obtain. The Company maintains an umbrella liability insurance policy for all of its operations, and requires liability policies to be furnished by contract operators, naming the Company as a co-insured. The coal industry in the past has been highly competitive, with very thin margins in recent years. Only in the past two years, in the opinion of management, have the economics begun to look favorable to coal again. This situation is due, in part, to the surge in prices of natural gas. The price increases of natural gas, on a Btu basis, have reached the point that coal fired power plants, using the latest clean air compliant scrubber technology can be price competitive with natural gas fired plants. -26- The Company intends to exploit its' mineral rights by opening mines, as its capital will allow, but it can only open a mine with an estimated $500,000 to $750,000 per mine, including bonds or cash deposited. Due to the operating capital constraints, if the Company cannot raise such needed additional amounts by loans or private placements, it will prevent the Company from expanding its' mining operations beyond the current operations. NOTE: The Company cannot now compute any "reserves" because only one of its' properties is in production. "Reserves", to be so classified, must be based upon reasonably accurate scientific data and professional analysis, be recoverable (economically and physically), have a permitted and operating mine facility at the coal location, and be subject to current sales. All of these criteria have not been met on the Company's mineral rights. The Company has, however, estimated potential tonnages in its mineral rights, based upon information available to it and professional reports by a qualified professional geologist, for internal use only. Significant Accounting Policies and Estimates The discussion and analysis of the Company's financial condition and results of operations are based upon its' consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, the Company evaluates its' estimates, including those related to computing depreciation, depletion, amortization, reclamation, asset impairment, valuation of non-cash transactions and recovery of receivables. Estimates are then based on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. The Company's use of estimates, however, is quite limited, as it has adequate time to process and record actual results from operations. Significant accounting policies are described in Note 2 to the consolidated financial statements included in Item 7 of this Form 10-KSB. The Company believes its' most critical accounting policies include revenue recognition, the corresponding accounts receivable and the methods of estimating depletion and accretion expense of actual mining operations in relation to estimated total mineable tonnage on its' New River Tract property. The Company believes the following accounting policies affect its' more significant judgments and estimates used in preparation of its' consolidated financial statements. Revenue Recognition Under SEC Staff Accounting Bulletin No. 101, "Revenue Recognition in Financial Statements," the Company recognizes revenue when all of the following criteria are met: (1) persuasive evidence of an arrangement exists, (2) delivery has occurred or services have been rendered, (3) the seller's price to the buyer is fixed or determinable, and (4) collectibility is reasonably assured. In the case of the Company's product, a price is negotiated with each customer with specifics for requirements, a fixed price per ton, a delivery schedule, and terms for payment. Unless cash is paid in advance, accounts receivables are recorded as revenue is earned. The Company regularly evaluates the collectibility of its' receivables based on a combination of factors. To date, the Company has not had any customer whose payment was considered past due, and as such has not had to record any reserves for doubtful collectibility. -27- Asset Retirement Obligation The Company's asset retirement obligations arise from the federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. Significant reclamation activities include reclaiming refuse and slurry ponds, reclaiming the pit and support acreage at surface mines, and sealing portals at deep mines. Reclamation activities that are performed outside of the normal mining process are accounted for as asset retirement obligations in accordance with the provisions of SFAS 143. The Company records its reclamation obligations on a mine-by-mine basis based upon current permit requirements and estimated reclamation obligations for such mines as determined by the Office of Surface Mining when the Company, prior to the Company commencing its' mining operations under each permit, posts a predetermined amount of reclamation bonds. The Office of Surface Mining's estimates of disturbed acreage are determined based on approved mining plans and related engineering data. Cost estimates are based upon estimates prepared by the OSM based on historical costs. In accordance with the provisions of SFAS 143, the Company determines the fair value of its asset retirement obligations. In order to determine fair value, the Company also estimates a discount rate, as discussed further below: Discount rate -- SFAS 143 requires that asset retirement obligations be recorded at fair value. In accordance with the provisions of SFAS 143, the Company utilized a discounted cash flow technique to estimate the fair value of its obligations. The Company bases its discount rate on the rates of treasury bonds with maturities similar to expected mine lives, adjusted for its credit standing. On at least an annual basis, the Company reviews its entire reclamation liability and makes necessary adjustments for permit changes as granted by state authorities, additional costs resulting from accelerated mine closures, and/or revisions to cost estimates and productivity assumptions, to reflect current experience. At December 31, 2003, the Company had recorded asset retirement obligation liabilities of $64,400. While the precise amount of these future costs cannot be determined with certainty, as of December 31, 2003, the Company estimates that the aggregate undiscounted cost of final mine closure is approximately $257,500. RESULTS OF OPERATIONS FOR THE PERIOD FROM JANUARY 30, 2003 (INCEPTION OF NATIONAL COAL CORPORATION) TO DECEMBER 31, 2003 Since the formation of National Coal Corporation on January 30, 2003, it had been deemed to be in the exploration stage because the Company did not have any direct coal mining operations or proven reserves. However, during the three-month period ended September 30, 2003, production commenced and accordingly, the Company is no longer considered to be in the exploration stage. For the eleven months ended December 31, 2003, the Company had revenues of $1,190,600 consisting of coal sales of $1,012,500 and royalty receipts of $178,100, and a net loss of $3,332,900 primarily due to mine operations and selling expenses of $1,657,600, exploration and development expenses of $80,400, and general and administrative expenses of $1,871,400. The Company also incurred $372,400 of interest expense related primarily to the issuance of notes payable, and $366,600 of amortization expense related to the amortization of loan acquisition costs. Revenue For the eleven-month period ended December 31, 2003, the Company's coal sales revenue resulted from the sale of a total of 35,125 tons of coal at an average price per ton of approximately $28.83. The Company's top three customers accounted for over 93% of total sales, with its' top customer representing 51.8%; its' second highest customer representing 26.8%; and its' third top customer representing 14.6%. The sales to both the #1 and #3 customers were conducted on a spot price basis, and the sales to 2nd highest customer was pursuant to multiple short-term sales contracts. -28- Cost of Mining Operations and Selling Expenses For the eleven-month period ended December 31, 2003, the Company incurred direct cost of mining operations and selling expenses of $1,657,600. These expenses consisted primarily of (1) salary, benefits and other compensation costs paid directly to miners of $431,300; (2) direct costs paid to third party vendors whose goods and services were directly used in the process of producing coal, such as equipment leases and maintenance expenses ($470,400), blasting ($158,800), fuel ($191,300), parts and supplies ($227,200), hauling costs ($65,700); and (3) selling commissions of $5,100. Exploration and Development Expenses For the eleven-month period ended December 31, 2003, the Company incurred exploration and development costs of $80,400, consisting of $78,200 of professional fees paid to geological and exploration experts, and $2,200 paid for sample analysis fees. General and Administrative Expenses For the eleven-month period ended December 31, 2003, the Company incurred general and administrative costs of $1,871,400. These expenses consisted primarily of (1) salary, benefits and related expenses of $753,100, including $46,100 of accrued salary expenses payable to the Chairman; (2) executive, financial, and accounting consulting expenses of $706,500; (3) legal and other professional fees of $99,600; (4) insurance expenses of 59,600; and (5) travel and travel related expenses of $48,300. Interest, Amortization, Depreciation and Other Income/(Expense) Other significant expenses of the Company consisted primarily of (1) interest expenses of $372,100 related to the issuance of notes payable; (2) $366,600 of amortization expense related to financing fees paid in conjunction with the issuance of convertible notes in March 2003; and (3) $240,400 of depreciation expense. These expenses were offset by $75,400 of other income primarily derived from a $73,800 gain recognized with the sale of marketable securities. Common Stock Issuances for National Coal Corporation Prior to Reorganization Issuance of Stock for Services In January 2003, a total of 15,350,000 shares of common stock were granted to the four founding officers/directors of the Company for services rendered. The stock was valued at $153,500 ($0.01 per share) based on stock transactions for cash with unrelated individuals (see below). Issuance of Stock for Cash In January and February 2003, a total of 1,750,000 shares of common stock were sold to individuals for $17,500 ($0.01 per share). Convertible Debt and Warrants to Purchase Common Stock In March 2003, the Company issued two convertible notes payable for a total of $3,194,902. The notes and related accrued interest are convertible into common stock at $0.50 per share. The convertible note holders also received warrants to purchase a total of 1,597,250 shares of common stock at $0.55 per share. The warrants have an expiration of two years from the date of issuance. As of December 31, 2003, none of the warrants had been exercised. -29- Reorganization On March 28, 2003, National Coal Corporation (Tennessee) entered into an Agreement and Plan of Reorganization to acquire 34.2 million shares of Southern Group International, Inc. common stock for all of National Coal Corporation's (Tennessee) outstanding common stock and $50,000 to retire 500,000 shares of SGI common stock. The $50,000 payment was made in March 2003 and recorded as an administrative expense. The shares were exchanged on April 30, 2003. Immediately after the transaction, the former National Coal Corporation (Tennessee) shareholders owned approximately 94.8% of SGI's common stock. Coincident with the transaction, SGI changed its' name to National Coal Corporation. The reorganization was recorded as a recapitalization effected by a reverse merger wherein NCC/SGI was treated as the acquiree for accounting purposes, even though it was the legal acquirer. Since SGI was a non-operating entity with limited business activity, goodwill was not recorded. An unaudited pro forma summary of consolidated net liabilities on March 31, 2003 is set forth below:
NCC NCC/SGI Consolidated --- ------- ------------ Cash and equivalents $1,220,798 $ 227 $ 1,221,025 Other current assets 5,000 - 5,000 Other assets 1,736,510 - 1,736,510 Notes payable and current liabilities (3,585,766) (13,922) (3,599,688) ----------- ---------- ----------- Net liabilities $ (623,458) $ (13,695) $ (637,153) =========== =========== ===========
The following unaudited pro forma consolidated results of operations is for the twelve months ended March 31, 2003 and 2002 (which includes NCC activity solely for the period since its inception to March 31, 2003) and assumes the business combination had occurred April 1, 2001: Year Ended March 31, 2003 2002 --------- ---------- Revenues .................................. $ -0- $ -0- ========= ========== Net income (loss) ......................... $(804,705) $ (26,039) ========= ========== Net income (loss) per share* .............. $ (.02) $ (.00) ========= ========== (*) Based on 1,887,381 SGI shares outstanding prior to the reverse merger and 34,200,000 SGI shares issued as a result of the merger. In management's opinion, the unaudited pro forma results of operations are not indicative of the actual results that would have occurred if the acquisition had taken place at the beginning of the periods presented and are not intended to be a projection of future results. Related Party Transactions On February 26, 2003, NCC acquired mining equipment and certain other intangible mining rights and information from Strata Coal, LLC ("Strata") for $47,000 ($7,000 cash and a non-interest bearing promissory note) and assumption of promissory notes payable to unrelated parties totaling $174,000. The Company also assumed $14,875 of Strata accounts payable. Strata is owned by the Chairman of the Board and the President/CEO of NCC. Since the Strata transaction involved related parties, primarily for intangible consideration, the $205,875 purchase price (exclusive of the mining equipment subsequently sold - see below), has been expensed. Subsequent to March 31, 2003 the promissory notes (totaling $214,000) have been paid, and on June 11, 2003, the mining equipment was sold to Jenco Capital Corporation ("Jenco") for $30,000. The President of NCC is also a stockholder of Jenco. -30- In February 2003, the Company borrowed $150,000 from a trust owned by the Chairman of the Board. This note accrues simple interest at an annual rate of 8% and was to mature in February 2005. In August 2003, the Company and Chairman agreed to extend the maturity date of such note for three additional years. The new maturity date is now February 20, 2008. No additional compensation was paid to the Chairman for such maturity extension. The note is classified as a current liability in the balance sheet due to the related party nature of the obligation. On March 31, 2003, the Company paid the Chairman of the Board and its President/CEO $150,000 each for organization, development and promotion activities to get the Company started. On July 1, 2003, the Company sold mineral royalty rights for coal mined on the Patterson Mountain portion of its' New River Tract for $75,156 to Jenco Capital Corporation ("Jenco"), an entity partially owned by the CEO/President of the Company. As consideration for the $75,156 received, the Company is obligated to pay Jenco $2.00 per mined ton on the property. During the six months ended December 31, 2003, the Company paid Jenco $59,572 in accordance with this transaction. On August 1, 2003, the Company sold its interest in mineral royalty rights received by the Company from U.S. Coal, Inc. for coal mined on the Smokey Mountain portion of the New River Tract. The royalty was sold for $250,000 to Jenco. As consideration for the $250,000 received, Jenco began receiving the royalty payments from U.S. Coal. The Company recorded the transaction as deferred revenue and recognizes revenue each month based on U.S. Coal's production. As of December 31, 2003, royalties totaling $146,597 have been recognized, leaving $103,403, which is included in deferred revenue. These transactions were completed by the Company with Jenco, a related party, because (i) the Company needed a prompt capital infusion to ramp up coal production, (ii) Jenco had available cash for the transaction, (iii) the Company could not have developed another independent source for the capital without considerable time delay due to lack of a production history, and (iv) the Company had no knowledge of any outside sources for such capital. The Company believes that given the time delay to search for capital and the cost of lost opportunity, the terms of these transactions were acceptable because it afforded immediate liquidity for operating purposes. On June 30, 2003, the Board of Directors assigned a ten-year, $0.25 per ton royalty interest on all the coal sold from the Company's New River Tract, to both the Chairman of the Board and the CEO/President. In the event any mineral properties are sold prior to the end of the ten-year period, the obligation is to be settled by paying 12 1/2% of the sales price to each individual. Pursuant to the sale of mineral property rights to Jenco (see two paragraphs above), the Company has recorded a liability to pay both the Chairman of the Board and the CEO/President 12 1/2% of the sales price, a total of $81,289. The obligations were paid in February 2004 and concurrently the June 30, 2003 agreements were canceled. In August 2003, the Company borrowed $250,000, in October 2003, the Company borrowed $25,000, and in December 2003, the Company borrowed $30,000, from Jenco. In December 2003, the Company borrowed $105,000 from the CEO/President of the Company. The notes payable accrue simple interest at an annual rate of 8% and are payable on demand. In October 2003, the Company loaned the Chief Financial Officer $15,000 at an annual interest rate of 3 1/2% and a maturity of 1 year. This loan was made during the period of time that the CFO was performing his duties on an interim basis and was not considered an officer of the Company. In February 2004, this loan, plus accrued interest, was paid in full. During 2003, the Company paid the law firm of Kite, Bowen & Associates, PA $45,000 for professional services rendered. Mr. Kite is the managing partner of Kite, Bowen & Associates, PA, and is a director of the Company. -31- Common Stock Transactions Subsequent to the April 2003 merger of NCC/SGI, 1,350,000 shares of SGI common stock were issued for a total of $270,000. In June 2003, 421,450 shares of SGI common stock were re-purchased for $21,073 and cancelled. Contract with Financial Consultants On April 7, 2003, the Company entered into a personal service contract with a financial consultant at $2,500 per month for twelve months. On July 24, 2003, the Company contracted with a consultant to prepare a Private Placement Memorandum describing the Company for $10,000. Information Technology Contracts On April 3, 2003, the Company entered into a contract to acquire managerial and financial application software for $38,250. On April 14, 2003, the Company retained a consultant to design the Company's website for approximately $25,600. Agreements with Officers In April and July 2003, the Board of Directors entered into employment agreements with the Chairman, the President/CEO, and the Secretary/Treasurer each for a two-year period providing for bonuses not to exceed fifty percent of the annual salaries, and in September 2003 entered into an employment agreement with the Chief Financial Officer for a six-month period providing for a bonus not to exceed fifty percent of the annual salary, all as set forth below: Chairman of the Board $240,000 President & CEO 240,000 Chief Financial Officer 144,000 Secretary/Treasurer 96,000 In March 2004, the Chairman agreed to reduce his annual base salary to $36,000. This agreement was entered into as a result of the Chairman taking a much less active role in the day-to-day operations of the Company. Concurrent with this reduction in annual base salary, the Chairman, who had been accruing his salary since October 2003, agreed to receive all previously accrued salary in stock, using a price per share of $0.55. This resulted in the issuance of 167,832 shares to the Chairman in March 2004. In February 2004, the Chief Financial Officer agreed to a permanent position with the Company, and as consideration, the Company increased his annual base salary from $144,000 to $168,000. On June 30, 2003, the Board of Directors assigned a ten-year, $0.25 per ton royalty interest on all the coal sold from the Company's New River Tract, to both the Chairman of the Board and the CEO/President. In the event any mineral properties are sold prior to the end of the ten-year period, the obligation is to be settled by paying 12 1/2% of the sales price to each individual. Pursuant to the sale of mineral property rights to Jenco (see two paragraphs above), the Company has recorded a liability to pay both the Chairman of the Board and the CEO/President 12 1/2% of the sales price, a total of $81,289. The obligations were paid in February 2004 and concurrently the June 30, 2003 agreements were canceled. -32- Commitments and Contingencies Leases In March 2003, the Company agreed to lease space in Georgia, on a month-to-month basis, at $600 per month. In April 2003, the Company entered into an agreement to lease its' Knoxville office for nine months at $1,800 per month, with an option to renew for an additional nine months. Rental expense for these lease commitments totaled approximately $22,200 through December 31, 2003. Acquisitions and Dispositions of Mineral Interests On April 9, 2003, the Company acquired approximately 65,000 acres of coal mineral rights underlying properties in Anderson, Campbell and Scott Counties, Tennessee for $1,270,000 (the "New River Tract"). A deposit for the purchase price of the property was made on March 27, 2003, of which $40,000 was paid to a law firm owned by a director of the Company. On May 20, 2003, the Company entered into a $1,196,000 contract to acquire coal mineral rights underlying properties in Anderson and Campbell Counties, Tennessee. The Company paid $50,000 in June as a deposit towards the closing of this transaction, which was scheduled to close on July 8, 2003. The closing did not occur on July 8, 2003, and the Company requested and subsequently received an amendment to extend the closing date. The amended agreement called for monthly payments, commencing September 22, 2003, of $100,000, a portion of which would be paid as an interest charge. On September 30, 2003, the Company requested and subsequently received a second amendment, which waived the $100,000 payment due on September 22, 2003. As consideration for the extension, the Company paid $10,000. The Company subsequently missed the next $100,000 payment date of October 22, 2003. Consequently, the Company no longer has the right to acquire these properties, and in September 2003 the Company wrote off the previously paid $60,000. On July 1, 2003, the Company sold mineral royalty rights for coal mined on the Patterson Mountain portion of its' New River Tract for $75,156 to Jenco, an entity partially owned by the CEO/President of the Company. As consideration for the $75,156 received, the Company is obligated to pay Jenco $2.00 per mined ton on the property. During the six months ended December 31, 2003, the Company paid Jenco $59,572 in accordance with this transaction. On August 1, 2003, the Company sold its interest in mineral royalty rights received by the Company from U.S. Coal, Inc. for coal mined on the Smokey Mountain portion of the New River Tract. The royalty was sold for $250,000 to Jenco. As consideration for the $250,000 received, Jenco began receiving the royalty payments from U.S. Coal. The Company recorded the transaction as deferred revenue and recognizes revenue each month based on U.S. Coal's production. As of December 31, 2003, royalties totaling $146,597 have been recognized, leaving $103,403, which is included in deferred revenue. Mining Equipment In April and June 2003, the Company entered into contracts to purchase mining equipment totaling $170,500. On May 30, 2003, the Company entered into short-term lease agreements for mining equipment with initial combined monthly rents totaling $91,900 and approximately $1,036,000 over the lease terms. -33-
Notes Payable Notes payable at December 31, 2003 consisted of the following: 1. Convertible notes payable dated March 24, 2003, 12% interest, payable with accrued interest upon the earlier of 1) March 25, 2004, or 2) the closing of certain financing, merger or disposition activities. (Extended to March 25, 2005) $3,194,902 2. Note payable to a trust owned by an officer dated February 20, 2003, 8% interest, payable with accrued interest upon the earlier of 1) February 20, 2008, or 2) the closing of certain financing, merger or disposition activities. 150,000 3. Note payable to an entity partially owned by an officer dated August 27, 2003, 8% interest, payable with accrued interest upon the earlier of 1) February 27, 2004, or 2) the closing of certain financing, merger or disposition activities. 250,000 4. Note payable to an entity partially owned by an officer dated October 30, 2003, 8% interest, and payable, with accrued interest, upon demand. 25,000 5. Note payable dated November 7, 2003, 10% interest, payable March 7, 2004. 33,000 6. Note payable dated November 7, 2003, 10% interest, payable March 7, 2004. 55,000 7. Note payable dated September 25, 2003, 12% interest, payable with accrued interest upon the earlier of 1) September 25, 2004, or 2) the closing of certain financing, merger or disposition activities. 75,000 8. Note payable dated September 30, 2003, 12% interest, payable with accrued interest upon the earlier of 1) September 30, 2004, or 2) the closing of certain financing, merger or disposition activities. 195,315 9. Note payable dated November 7, 2003, 10% interest, payable March 7, 2004. 50,000 10. Note payable dated November 7, 2003, 10% interest, payable March 7, 2004. 60,000 11. Note payable to an entity partially owned by an officer dated December 1, 2003, 8% interest, and payable, with accrued interest, upon demand. 30,000 12. Note payable to the President/CEO dated December 23, 2003, 8% interest, and payable, with accrued interest, upon demand. 95,000 13. Note payable to the President/CEO dated December 24, 2003, 8% interest, and payable, with accrued interest, upon demand. 10,000 ---------- Total $4,223,217 ==========
Other Contractual Obligations During the second calendar quarter, the Company entered into short-term capital lease agreements to acquire four mining vehicles with a combined estimated fair value of $775,916, which approximates the present value of the minimum lease payments. Amortization is included in depreciation expense. Additionally, the Company rents other mining equipment pursuant to operating lease agreements, and made lease payments totaling $307,478 during 2003. In March 2003, the Company agreed to lease space in Georgia, on a month-to-month basis, at $600 per month. In April 2003, the Company entered into an agreement to lease its' Knoxville office for nine months at $1,800 per month, with an option to renew for an additional nine months. Rental expense for these lease commitments totaled approximately $22,200 through December 31, 2003. -34- A summary of future minimum payments under non-cancelable capital and operating lease agreements, as well as other contractual obligations of the Company, as of December 31, 2003 follows:
Other Contractual Obligations Payments due by period ----------------------------- ---------------------- Less than 1 More than 5 Total year 1-3 years 3-5 years years ----- ---- --------- --------- ----- Capital Lease Obligations $476,000 $476,000 $0 $0 $0 Operating Leases $138,000 $138,000 $0 $0 $0 Property Leases $16,000 $16,000 $0 $0 $0 Employment Obligations $429,000 $336,000 $ 93,000 $0 $0 Total Other Contractual Obligations $1,059,000 $966,000 $ 93,000 $0 $0
Liquidity As of December 31, 2003, the Company's had a cash and cash equivalents position of $883. The Company's operations generated negative cash flow during the eleven months ended December 31, 2003, and it expects a significant use of cash during the first half of fiscal 2004 as the Company continues to initiate the business opportunity for its' coal mining operations. It is anticipated that the current cash reserves (including the cash raised in the February 2004 equity private placement), plus expected generation of cash from operations, which have recently commenced, will only be sufficient to fund the anticipated expenditures into the third quarter of 2004. Consequently, the Company will require additional equity or debt financing during the first half of 2004, the amount and timing of which will depend in large part on the Company's spending program. If additional funds are raised through the issuance of equity securities, the current stockholders may experience dilution. Furthermore, there can be no assurance that additional financing will be available when needed or that if available, such financing will include terms favorable to the stockholders of the Company. If such financing is not available when required or is not available on acceptable terms, the Company may be unable to develop or enhance its mining operations, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on the business, financial condition and results of operations of the Company. No operations were conducted and no operating revenue was realized from January 30, 2003 to June 30, 2003, and the Company only began mining operations during the calendar third quarter 2003. As of December 31, 2003, the Company was totally illiquid and needed cash infusions from shareholders to provide capital, or needed loans from any sources available. At December 31, 2003, the Company had negative working capital of approximately $5,512,000 and a stockholders' deficiency of approximately $2,927,000. These factors raise substantial doubt about the Company's ability to continue as a going concern. Short Term On a short-term basis, the Company does not generate revenue sufficient to cover operations. Based on prior experience, the Company believes it will continue to have insufficient revenue to satisfy current and recurring liabilities as it seeks to develop its coal operations. For short-term needs, the Company will be dependent on receipt, if any, of outside financing proceeds, including debt and equity, any of which may be dilutive to existing shareholders. At December 31, 2003, the Company's current assets of $181,270 were exceeded by its current liabilities $5,693,115. -35- Long Term The Company has no cash commitments in hand from any source to fund its long-term prospects. The Company does have a plan in place to resolve this issue; it plans to raise outside capital from either debt or equity sources (or both), however additional capital may or may not be available to the Company, and if available, the terms may not be favorable to the Company and its' shareholders. Failure to obtain long-term capital funding could result in failure of the Company. Capital Resources The primary capital resources of the Company are its common stock, and coal as it is produced and sold. Cash Flows The Company has only achieved negative cash flows to date, in the amount of ($1,541,409) from operating activities. $3,533,171 was provided from financing activities. The net loss for the eleven-month period ended December 31, 2003 was ($3,332,885). The Company expects cash flows to remain negative from operations until production can be ramped up and/or new mines can be opened, all of which requires additional capital for which the Company has no committed sources, and there are no assurances that such funding sources can be found. Need for Additional Financing The Company does not have capital sufficient to meet the Company's cash needs, or to expand its' mining business. The Company will have to seek loans or equity placements to cover all cash needs. As operations increase, the Company's need for additional financing is likely to increase, which will have a dilutive effect to shareholders. No commitments to provide additional funds have been made by management or other outside sources. Accordingly, there can be no assurance that any additional funds will be available to the Company to allow it to cover its' expenses and current liabilities as they incur. The Company is currently in early stage discussions with multiple outside sources of capital, however no assurances can be made about the successful outcome of these discussions. -36- DESCRIPTION OF PROPERTIES/ASSETS/TECHNOLOGY (a) Real Estate. Mineral Rights. The Company owns the following: 65,000 acres of coal mineral rights in the "New River Tract." These mineral rights revert back to the surface owner on June 5, 2093. SEAM LOCATION MEASURED ACRES ====================== ========================== ==================== Jellico Coon Pool Branch 496 Jellico Cage Creek 1,230 Windrock Buffalo Mountain 1,632 Big Mary High Point 567 Big Mary High Point Mountain 395 Big Mary Ash Log Mountain 593 Big Mary Red Oak Mountain 421 Walnut Mt. High Point 193 Walnut Mt. Buffalo Mountain 624 Pewee Fork Mountain 286 Pewee Stallion Mountain 486 Pewee R High Point 139 Pewee R Burge Mountain 380 Pewee R Hannah Top 94 (b) Technology. None. (c) Patents. None. RISK FACTORS RELATING TO THE COMPANY AND BUSINESS Several of the matters discussed in this document contain forward-looking statements that involve risks and uncertainties. Factors associated with the forward-looking statements that could cause actual results to differ materially from those projected or forecast are included in the statements below. In addition to other information contained in this report, readers should carefully consider the following cautionary statements. Going Concern. The Company currently has a number of obligations that it is unable to meet without generating additional revenues or raising additional capital. If the Company cannot generate additional revenues or raise additional capital in the near future, it may become insolvent. As of December 31, 2003, the Company's cash balance was a $883 and its' outstanding accounts payable and accrued expenses totaled more than $832,000. Historically, the Company has funded its capital requirements with debt and equity financing. Its ability to obtain additional equity or debt financing depends on a number of factors including the financial performance and the overall conditions in the coal industry. If the Company is not able to raise additional financing or if such financing is not available on acceptable terms, the Company may liquidate assets, seek or be forced into bankruptcy, and/or continue operations, but suffer material harm to its' operations and financial condition. These measures could have a material, adverse affect on the Company's ability to continue as a going concern. -37- Competition. There are numerous competitors in the coal business with substantially greater resources than the Company. Such resources could overwhelm the Company's efforts to operate successfully and cause failure of the Company. Working Capital. The working capital needs of the Company consist of: debt reductions and interest service, mine development, property acquisition and exploration costs, bonding costs, equipment expenditures and compensation payments for mining. Limited Revenues. The Company has achieved limited revenues to date consisting of approximately $1,800,000 in coal sales, through the end of February 2004. There is no assurance that the Company can achieve any greater sales or maintain any profitable sales. Industry Factors. The Company expects that many coal producers could produce and sell coal at cheaper prices per ton than the Company's production cost rates, which could adversely affect the Company's revenues and profits, if any. Conflicts of Interest. Certain conflicts of interest may exist between the Company and its officers and directors. They have other business interests to which they devote their attention, and they may be expected to continue to do so although management time should be devoted to the business of the Company. As a result, conflicts of interest may arise that can be resolved only through exercise of such judgment as is consistent with fiduciary duties to the Company. Need for Additional Financing. The Company has limited funds, and such funds may not be adequate to carry out the business plan. The ultimate success of the Company may depend upon its ability to raise substantial amounts of additional capital. The Company has not investigated the availability, source, or terms that might govern the acquisition of additional capital and will not do so until it determines a need for additional financing. If additional capital is needed, there is no assurance that funds will be available from any source or, if available, that they can be obtained on terms acceptable to the Company. If not available, the Company's operations will be limited to those that can be financed with its modest capital and cash flows, if any. Regulation of Penny Stocks. The Company's securities, as traded on the "Pink Sheets", will be subject to a Securities and Exchange Commission rule that imposes special sales practice requirements upon broker-dealers who sell such securities to persons other than established customers or accredited investors. For purposes of the rule, the phrase "accredited investors" means, in general terms, institutions with assets in excess of $5,000,000, or individuals having a net worth in excess of $1,000,000 or having an annual income that exceeds $200,000 (or that, when combined with a spouse's income, exceeds $300,000). For transactions covered by the rule, the broker-dealer must make a special suitability determination for the purchaser and receive the purchaser's written agreement to the transaction prior to the sale. Consequently, the rule may affect the ability of broker-dealers to sell the Company's securities and also may affect the ability of purchasers in this offering to sell their securities in any market that might develop therefore. In addition, the Securities and Exchange Commission has adopted a number of rules to regulate "penny stocks". Such rules include Rules 3a51-1, 15g-1, 15g-2, 15g-3, 15g-4, 15g-5, 15g-6, 15g-7, and 15g-9 under the Securities and Exchange Act of 1934, as amended. Because the securities of the Company may constitute "penny stocks" within the meaning of the rules, the rules would apply to the Company and to its securities. The rules may further affect the ability of owners of the Company's common stock to sell the securities of the Company in any market that might develop for them. -38- Shareholders should be aware that, according to Securities and Exchange Commission, the market for penny stocks has suffered in recent years from patterns of fraud and abuse. Such patterns include (i) control of the market for the security by one or a few broker-dealers that are often related to the promoter or issuer; (ii) manipulation of prices through prearranged matching of purchases and sales and false and misleading press releases; (iii) "boiler room" practices involving high-pressure sales tactics and unrealistic price projections by inexperienced sales persons; (iv) excessive and undisclosed bid-ask differentials and markups by selling broker-dealers; and (v) the wholesale dumping of the same securities by promoters and broker-dealers after prices have been manipulated to a desired consequent investor losses. The Company's management is aware of the abuses that have occurred historically in the penny stock market. Although the Company does not expect to be in a position to dictate the behavior of the market or of broker-dealers who participate in the market, management will strive within the confines of practical limitations to prevent the described patterns from being established with respect to the Company's securities. Lack of Revenue History. The Company was formed to create a regional coal producer in Tennessee. The Company had no revenues from inception until the third quarter 2003 when it began mining operations. The Company is not profitable and the business status is considered to be in an early development stage. The Company must be regarded as a risky venture with all of the unforeseen costs, expenses, problems, risks and difficulties to which such ventures are subject. No Assurance of Success or Profitability. There is no assurance that the Company will ever operate profitably. There is no assurance that it will generate continued revenues or any profits, or that the market price of the Company's common stock will be increased thereby. Lack of Diversification. Because of the limited financial resources that the Company has, it is unlikely that the Company will be able to diversify its operations. The Company's probable inability to diversify its activities into more that one business area will subject the Company to economic fluctuations within a particular business or industry and therefore increase the risks associated with the Company's operations. Dependence upon Management. The Company currently has two individuals who are serving as its officers on a full time basis and one executive who serves as Chairman of the Board. One director serves on a part-time basis, about 20 hours a month. The Company is heavily dependent upon their skills, talents, and abilities, as well as consultants to the Company, to implement its business plan, and may, from time to time, find that the inability of the directors and other officers to devote their full time attention to the business of the Company results in a delay in progress toward implementing its business plan. Indemnification of Officers and Directors. Florida Revised Statutes provide for the indemnification of its directors, officers, employees, and agents, under certain circumstances, against attorney's fees and other expenses incurred by them in any litigation to which they become a party arising from their association with or activities on behalf of the Company. The Company will also bear the expenses of such litigation for any of its directors, officers, employees, or agents, upon such person's promise to repay the Company therefore, if it is ultimately determined that any such person shall not have been entitled to indemnification. This indemnification policy could result in substantial expenditures by the Company that it will be unable to recoup. Director's Liability Limited. Florida Revised Statutes exclude personal liability of its directors to the Company and its stockholders for monetary damages for breach of fiduciary duty except in certain specified circumstances. Accordingly, the Company will have a much more limited right of action against its directors than otherwise would be the case. This provision does not affect the liability of any director under federal or applicable state securities laws. -39- Dependence upon Outside Advisors. To supplement the business experience of its officers and directors, the Company may be required to employ accountants, technical experts, appraisers, attorneys, or other consultants or other advisors. The Company's CEO/President, without any input from stockholders, will make the selection of any such advisors. Furthermore, it is anticipated that such persons may be engaged on an "as needed" basis without a continuing fiduciary or other obligation to the Company. In the event the CEO/President of the Company considers it necessary to hire outside advisors, he may elect to hire persons who are affiliates, if they are able to provide the required services. No Foreseeable Dividends. The Company has not paid dividends on its common stock and does not anticipate paying such dividends in the foreseeable future. Loss of Control by Present Management and Stockholders. The Company may issue further shares as consideration for the cash or assets or services out of the Company's authorized but not issued common stock that would, upon issuance, represent a majority of the voting power and equity of the Company. The result of such an issuance would be that those new stockholders and management would control the Company, and persons unknown could replace the Company's management at this time. Such an occurrence would result in a greatly reduced percentage of ownership of the Company by its current shareholders. Limited Public Market Exists. There is a limited public market for the Company's common stock in the "Pink Sheets", and no assurance can be given that a market will continue or that a shareholder ever will be able to liquidate his investment without considerable delay, if at all. The price may be highly volatile. Factors such as those discussed in the "Risk Factors" section may have a significant impact upon the market price of the securities offered hereby. Due to the low price of the securities, many brokerage firms may not be willing to effect transactions in the securities. Even if a purchaser finds a broker willing to effect a transaction in these securities, the combination of brokerage commissions, state transfer taxes, if any, and any other selling costs may exceed the selling price. Further, many lending institutions will not permit the use of such securities as collateral for any loans. Rule 144 Sales. All of the outstanding shares of common stock held by present officers, directors, and affiliate stockholders are "restricted securities" within the meaning of Rule 144 under the Securities Act of 1933, as amended. As restricted shares, these shares may be resold only pursuant to an effective registration statement or under the requirements of Rule 144 or other applicable exemptions from registration under the Act and as required under applicable state securities laws. Rule 144 provides in essence that a person who has held restricted securities for one year may, under certain conditions, sell every three months, in brokerage transactions, a number of shares that does not exceed the greater of 1.0% of a company's outstanding common stock or the average weekly trading volume during the four calendar weeks prior to the sale. There is no limit on the amount of restricted securities that may be sold by a non-affiliate after the owner has held the restricted securities for a period of two years. A sale under Rule 144 or under any other exemption from the Act, if available, or pursuant to subsequent registration of shares of common stock of present stockholders, may have a depressive effect upon the price of the common stock in any market that may develop. INDUSTRY RISK FACTORS If we are unable to achieve supply contracts, our revenues and operating profits could suffer if we were unable to find buyers willing to purchase our coal at profitable prices. If transportation for our coal becomes unavailable or uneconomic for our customers, our ability to sell coal could suffer. Transportation costs represent a significant portion of the total cost of delivered coal and, as a result, the cost of transportation is a critical factor in a customer's purchasing decision. Increases in transportation costs could make our coal a less competitive source of energy or could make some of our operations less competitive than other sources of coal. Some coal supply agreements permit the customer to terminate the contract if the cost of transportation increases by an amount ranging from 10% to 20%, in any given 12-month period. -40- Coal producers depend upon rail, barge, trucking, overland conveyor and other systems to deliver coal to markets. While U.S. coal customers typically arrange and pay for transportation of coal from the mine to the point of use, disruption of these transportation services because of weather-related problems, strikes, lock-outs or other events could temporarily impair our ability to supply coal to our customers and thus could adversely affect our results of operations. Risks inherent to mining could increase the cost of operating our business. Our mining operations are subject to conditions beyond our control that can delay coal deliveries or increase the cost of mining at particular mines for varying lengths of time. These conditions include weather and natural disasters, unexpected maintenance problems, key equipment failures, variations in coal seam thickness, variations in the amount of rock and soil overlying the coal deposit, variations in rock and other natural materials and variations in geologic conditions. The government extensively regulates our mining operations, which imposes significant costs on us, and future regulations could increase those costs or limit our ability to produce coal. Federal, state and local authorities regulate the coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, reclamation and restoration of mining properties after mining is completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. In addition, significant legislation mandating specified benefits for retired coal miners affects our industry. Numerous governmental permits and approvals are required for mining operations. We are required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment. The costs, liabilities and requirements associated with these regulations may be costly and time-consuming and may delay commencement or continuation of exploration or production operations. The possibility exists that new legislation and/or regulations and orders may be adopted that may materially adversely affect our mining operations, our cost structure and/or our customers' ability to use coal. New legislation or administrative regulations (or judicial interpretations of existing laws and regulations), including proposals related to the protection of the environment that would further regulate and tax the coal industry, may also require us or our customers to change operations significantly or incur increased costs. The majority of our coal supply agreements contain provisions that allow a purchaser to terminate its contract, if legislation is passed that either restricts the use or type of coal permissible at the purchaser's plant or results in specified increases in the cost of coal or its use. These factors and legislation, if enacted, could have a material adverse effect on our financial condition and results of operations. In addition, the United States and over 160 other nations are signatories to the 1992 Framework Convention on Climate Change, which is intended to limit emissions of greenhouse gases, such as carbon dioxide. In December 1997, in Kyoto, Japan, the signatories to the convention established a binding set of emission targets for developed nations. Although the specific emission targets vary from country to country, the United States would be required to reduce emissions to 93% of 1990 levels over a five-year budget period from 2008 through 2012. Although the United States has not ratified the emission targets and no comprehensive regulations focusing on U.S. greenhouse gas emissions are in place, these restrictions, whether through ratification of the emission targets or other efforts to stabilize or reduce greenhouse gas emissions, could adversely impact the price of and demand for coal. According to the Energy Information Administration's Emissions of Greenhouse Gases in the United States 2001, coal accounts for 32% of greenhouse gas emissions in the United States, and efforts to control greenhouse gas emissions could result in reduced use of coal if electricity generators switch to sources of fuel with lower carbon dioxide emissions. Further developments in connection with regulations or other limits on carbon dioxide emissions could have a material adverse effect on our financial condition or results of operations. -41- Our future success depends upon our ability to continue acquiring and developing coal reserves that are economically recoverable. Our recoverable reserves will decline as we produce coal. We have not yet applied for the permits required or developed the mines necessary to use all of the coal deposits under our mineral rights. Furthermore, we may not be able to mine all of our coal deposits as profitably as we do at our current operations. Our future success depends upon our conducting successful exploration and development activities and acquiring properties containing economically recoverable coal deposits. Our current strategy includes increasing our coal deposits base through acquisitions of other mineral rights, leases, or producing properties and continuing to use our existing properties. Additionally, the federal government limits the amount of federal land that may be leased by any company to 150,000 acres nationwide. As of December 31, 2003, we leased no acres from the federal government. The limit could restrict our ability to lease significant federal lands. Our planned development and exploration projects and acquisition activities may not result in the acquisition of significant additional coal deposits and we may not have continuing success developing additional mines. Our mining operations are conducted on mineral rights owned by us. Because title to most of our mineral rights are not thoroughly verified until a permit to mine the property is obtained, our right to mine some of our leased coal deposits may be materially adversely affected, if defects in title or boundaries exist. In addition, in order to develop our coal deposits, we must receive various governmental permits. We cannot predict whether we will continue to receive the permits necessary for us to operate profitably in the future. If the coal industry experiences overcapacity in the future, our profitability could be impaired. During the mid-1970s and early 1980s, a growing coal market and increased demand for coal attracted new investors to the coal industry, spurred the development of new mines and resulted in added production capacity throughout the industry, all of which led to increased competition and lower coal prices. Similarly, an increase in future coal prices could encourage the development of expanded capacity by new or existing coal producers. Any overcapacity could reduce coal prices in the future. Our operations could be adversely affected if we fail to maintain required surety bonds. Federal and state laws require bonds or cash deposits to secure our obligations to reclaim lands used for mining, to pay federal and state workers' compensation, to secure coal lease obligations and to satisfy other miscellaneous obligations. As of December 31, 2003, we had outstanding $257,500 in cash deposited with the Department of the Interior for post-mining reclamation. Reclamation surety bonds are typically renewable on a yearly basis, if they are not posted with cash. Our failure to maintain, or inability to acquire, surety bonds that are required by state and federal law would have a material adverse effect on us. That failure could result from a variety of factors including the following: o lack of availability, higher expense or unfavorable market terms of new surety bonds; o restrictions on the availability of collateral for current and future third-party surety bond issuers under the terms of our indenture or new credit facility; and o the exercise by third-party surety bond issuers of their right to refuse to renew the surety. Our ability to operate our Company effectively could be impaired if we lose key personnel. We manage our business with key personnel, the loss of whom could have a material adverse effect on us. In addition, as our business develops and expands, we believe that our future success will depend greatly on our continued ability to attract and retain highly skilled and qualified personnel. We cannot make any assurances that key personnel will continue to be employed by us or that we will be able to attract and retain qualified personnel in the future. We have "key person" life insurance covering the President/CEO, Secretary/Treasurer, Directors, and the Operations Manager. Failure to retain or attract key personnel could have a material adverse effect on us. -42- Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition and results of operations. Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition and results of operations. Our business is affected by general economic conditions, fluctuations in consumer confidence and spending, and market liquidity, which can decline as a result of numerous factors outside of our control, such as terrorist attacks and acts of war. Future terrorist attacks against U.S. targets, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions affecting our customers may materially adversely affect our operations. As a result, there could be delays or losses in transportation and deliveries of coal to our customers, decreased sales of our coal and extension of time for payment of accounts receivable from our customers. Strategic targets such as energy-related assets may be at greater risk of future terrorist attacks than other targets in the United States. In addition, disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any, or a combination, of these occurrences could have a material adverse effect on our business, financial condition and results of operations. Our ability to collect payments from our customers could be impaired due to credit issues. Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. Our customer base may not be highly creditworthy. If deterioration of the creditworthiness of customers or trading counterparties occurs, our business could be adversely affected. -43- Item 7. Financial Statements The response to this item is submitted as a separate section of this report beginning on page F-1. -44- Item 8. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure In connection with the audits of the two most recent fiscal years and any interim period preceding resignation, no disagreements exist with any former accountant on any matter of accounting principles or practices, financial statement disclosure, or auditing scope of procedure, which disagreements if not resolved to the satisfaction of the former accountant would have caused him to make reference in connection with his report to the subject matter of the disagreement(s). The principal accountants' reports on the financial statements for any of the past two years contained no adverse opinion or a disclaimer of opinion, nor was qualified as to uncertainty, audit scope, or accounting principles except for the "going concern" qualification. Item 8a. Controls and Procedures Members of the company's management, including our Chief Executive Officer and President, Jon Nix, and Chief Financial Officer, Robert Chmiel, have evaluated the effectiveness of our disclosure controls and procedures, as defined by paragraph (e) of Exchange Act Rules 13a-15 or 15d-15, as of December 31, 2003, the end of the period covered by this report. Based upon that evaluation, Messrs. Nix and Chmiel concluded that our disclosure controls and procedures are effective. There were no changes in our internal control over financial reporting or in other factors identified in connection with the evaluation required by paragraph (d) of Exchange Act Rules 13a-15 or 15d-15 that occurred during the fourth quarter ended December 31, 2003 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. -45- PART III Item 9. Directors, Executive Officers, Promoters and Control Persons; Compliance With Section 16(a) of the Exchange Act The following table lists the names and ages of the executive officers and directors of the Company. The directors, with the exception of Mr. Chmiel who was appointed in February 2004, were appointed in May 2003 and will continue to serve until the next annual shareholders meeting or until their successors are appointed and qualified. All officers serve at the discretion of the Board of Directors. NAME AGE POSITION WITH THE COMPANY ---- --- ------------------------- Jon Nix 34 President/CEO & Director Robert Chmiel 43 CFO & Director Jeanne Bowen Nix 33 Secretary/Treasurer/General Counsel Farrald Belote, Jr. 67 Chairman of the Board Charles Kite 59 Director JON NIX; age 34; President, Chief Executive Officer and Director. Mr. Nix is National Coal's founder and possesses over eight years experience in the financial industry. He is the founder of Jenco Capital Corporation, a Tennessee consulting and holding corporation. He is also a cofounder of Medicine Arm-In-Arm, Inc., a nonprofit children's charity that provides medical services to underprivileged children around the world. He holds a Bachelor of Arts degree in Economics from the University of Tennessee, 1992. He has been a director and President of National Coal Corp., a Tennessee corporation, since January 2003, which is the operating subsidiary. ROBERT CHMIEL; age 43; Chief Financial Officer and Director. From December 2000 to April 2003 Mr. Chmiel served as CFO/COO of Brilliant Digital Entertainment, Inc. (AMEX: BDE), a publicly traded software firm where he managed 5 separate debt and equity financings. Previously, he was the President/COO (1999-2000) and co-founder of Phase2Media, Inc., a privately held Internet advertising sales and marketing firm. In 1998, Mr. Chmiel was CFO for BarnesandNoble.com (NASDAQ: BNBN) prior to the company's IPO. Mr. Chmiel was employed at the Walt Disney Company, where he served as Vice President, Finance & Operations (1995-1998) for the original team that launched Disney's online operations, after having joined the company in 1992 as Director of Finance & Operations for Disney Magazine Publishing. His other business experience includes working for Oppenheimer as an associate in the corporate finance department, and started his career as an internal auditor for the Dun & Bradstreet Corporation. Mr. Chmiel earned his MBA from the Wharton School of Business at the University of Pennsylvania in 1987 and his BA in Economics from the College of the Holy Cross in 1982. JEANNE BOWEN NIX; age 33; Secretary/Treasurer/General Counsel. Ms. Bowen Nix has held a license to practice law in the State of Tennessee since 1997. She is a junior partner in the East Tennessee law firm of Kite, Bowen & Associates, P.A. and specializes in general corporate matters and real estate services. She graduated cum laude from the University of Tennessee in May of 1993 with a Bachelor of Arts degree in Psychology, and received her Juris Doctorate degree from Louisiana State University Law School in May of 1997. Ms. Bowen Nix has been Secretary and Treasurer of National Coal Corp., a Tennessee corporation, since January 2003, which is the operating subsidiary. FARRALD BELOTE, JR.; age 68; Chairman of the Board. Mr. Belote has had business experience dating back to 1958 in the energy sector. He is presently CEO of Litigation Research in Houston, TX (1995-date). He is also a co-founder of Medicine Arm-In-Arm, Inc., a nonprofit children's charity that provides medical services to underprivileged children around the world. IBM Sales and Marketing, 1964-1984: with emphasis on the energy sector. BA, Mathematics, Texas A&M, 1958. He has been a director of National Coal Corporation, a Tennessee corporation, since January 2003, which is the operating subsidiary. -46- CHARLES KITE; age 59; Director. Mr. Kite, an attorney since 1973, is outside corporate counsel of National Coal Corp. He has a general practice in Sevierville, Tennessee, and specializes in commercial business representation, tax representation and litigation, estate planning, and probate matters. After serving ten years as the Senior Trial Attorney in the Office of the Chief Counsel for the Internal Revenue Service in Philadelphia, Pennsylvania and in Nashville, Tennessee, he transferred to Knoxville, Tennessee to assist in opening the Knoxville branch of the law offices of Heiskell, Donelson, Bearman, Adams, Williams & Kirsch. The next five years, Mr. Kite was a senior partner with the law firm of Brabson, Kite & Vance in Sevierville, Tennessee, and thereafter for the following seven years was a sole practitioner in association with various attorneys in the East Tennessee area. He is currently, and from 1997 has been, the managing partner in the law firm of Kite, Bowen & Associates, PA. He is a graduate of the University of Tennessee (JD-1973) and of Carson Newman College (BA-1967). He has been a director of National Coal Corporation since February 2003. Under the Florida Business Corporation Act and the Company's Articles of Incorporation, as amended, the Company's directors will have no personal liability to the Company or its' stockholders for monetary damages incurred as the result of the breach or alleged breach by a director of his "duty of care". This provision does not apply to the directors' (i) acts or omissions that involve intentional misconduct or a knowing and culpable violation of law, (ii) acts or omissions that a director believes to be contrary to the best interests of the corporation or its shareholders or that involve the absence of good faith on the part of the director, (iii) approval of any transaction from which a director derives an improper personal benefit, (iv) acts or omissions that show a reckless disregard for the director's duty to the corporation or its' shareholders in circumstances in which the director was aware, or should have been aware, in the ordinary course of performing a director's duties, of a risk of serious injury to the corporation or its' shareholders, (v) acts or omissions that constituted an unexcused pattern of inattention that amounts to an abdication of the director's duty to the corporation or its' shareholders, or (vi) approval of an unlawful dividend, distribution, stock repurchase or redemption. This provision would generally absolve directors of personal liability for negligence in the performance of duties, including gross negligence. Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling the Company pursuant to the foregoing provisions, the Company has been informed that in the opinion of the Securities and Exchange Commission, such indemnification is against public policy as expressed in the Act and is therefore unenforceable. The Company does not have an Audit Committee. The members of the Board sit as the Audit Committee. Robert Chmiel sits as the qualified financial expert on the Board of Directors, and is the CFO of the Company. No director, officer or beneficial owner of more than 10% of the Company's common stock, its only equity securities, or any other person subject to Section 16 of the Exchange Act failed to file reports required by Section 16(a) of the Securities Exchange Act during the most recent fiscal year or prior fiscal years, however reports on Form 4 were late in filing for Jon Nix and Farrald Belote. There are family relationships among the members of the Board of Directors and Management ad follows: Charles Kite, Director, is the Father of Jeanne Bowen Nix. Jeanne Bowen Nix, Secretary Treasurer, is the wife of Jon Nix, President -47-
Item 10. Executive Compensation SUMMARY COMPENSATION TABLE OF EXECUTIVES Other Securities Long Annual Restricted Underlying Term All Name & Comp- Stock Options/ Compensation Other Principal Salary Bonus ensation Award(s) SARS Options Compensation Position Year ($) ($) ($) ($) (#) (#)($) - ----------------------------------------------------------------------------------------------------------------------------------- Jon Nix President 2003 161,538 150,000 0 0 0 0 40,644 (*) - ----------------------------------------------------------------------------------------------------------------------------------- Jeanne Bowen Nix Secretary/Treasurer 2003 64,615 0 0 0 0 0 0 - ----------------------------------------------------------------------------------------------------------------------------------- Robert Chmiel, 2003 47,753 0 0 0 0 0 0 CFO - -----------------------------------------------------------------------------------------------------------------------------------
Directors' Compensation for 2003 Fiscal Year Securities Annual Consulting Number Underlying Long Term All Retainer Meeting Fees/Other of Options/ Compensation/ Other Fees Fees Fees Shares SARS Options SARS Compensation Name ($) ($) ($) (#) (#) ($) ($) - ----------------------------------------------------------------------------------------------------------------------------------- Jon Nix Director 0 0 0 0 0 0 0 - ----------------------------------------------------------------------------------------------------------------------------------- Farrald Belote Director 0 311,538 0 0 0 0 40,644 (*) - ----------------------------------------------------------------------------------------------------------------------------------- Charles Kite Director 0 0 45,000 (**) 0 0 0 0 - ----------------------------------------------------------------------------------------------------------------------------------- Robert Chmiel (***) Director 0 0 0 0 0 0 0 - ----------------------------------------------------------------------------------------------------------------------------------- (*) - Pursuant to a Royalty Agreement which provides for a $0.25 per ton bonus and upon sale of mineral interests, a fee in lieu of continuing royalty may be paid to release the royalty. This royalty agreement was cancelled in 2004.
(**) - Legal fees paid to Kite, Bowen & Assoc., PA for professional legal fees. (***) - Appointed in 2004. Code of Ethics: The Company has not adopted a Code of Ethics as of the date of this report. -48- Item 11. Security Ownership of Certain Beneficial Owners and Management The following table sets forth certain information known to the Company with respect to the beneficial ownership of the Company's common stock as of March 23, 2004 by (i) each person who is known by the Company to own beneficially more than 5% of the Company's common stock, (ii) each of the Company's directors and executive officers, and (iii) all officers and directors of the Company as a group. Except as otherwise listed below, the address of each person is c/o National Coal Corporation, 319 Ebenezer Road, Knoxville, TN 37923. Name and Address of Amount and nature of Beneficial Owner Beneficial Ownership (1) Percentage of Class - --------------------------------------------------------------------- Jon Nix (1)(2)(7) 15,450,000 36.3% - --------------------------------------------------------------------- Jeanne Bowen Nix (1)(2)(3)(6) 600,000 1.4% - --------------------------------------------------------------------- Charles Kite (3)(6) 600,000 1.4% - --------------------------------------------------------------------- Farrald Belote, Jr. (4)(5)(8) 15,574,832 36.6% - --------------------------------------------------------------------- Robert Chmiel 100,000 0.2% - --------------------------------------------------------------------- All Officers and Directors as a Group 32,324,832 76.0% - --------------------------------------------------------------------- Total Shares Issued and 42,552,162 Outstanding 1. Includes (i) 600,000 shares owned by Jeanne Bowen Nix, (ii) 400,000 shares owned by Perdase Holdings, Inc., an entity controlled by Jon Nix, and (iii) 700,000 shares owned by Jenco Capital Corporation, an entity of which Jon Nix is a beneficial owner. 2. Jon Nix and Jeanne Bowen Nix are husband and wife. 3. Jeanne Bowen Nix is Charles Kite's stepdaughter. 4. Includes 5,000,000 shares pursuant to an option agreement between Mr. Nix and Mr. & Mrs. Belote such that Mr. Nix has the option to purchase these shares not before June 1, 2004 and not after March 31, 2005. 5. These shares are jointly owned with Arlene Belote, Mr. Belote's wife. 6. These shares are jointly owned with Christine Kite, Mr. Kite's wife and mother of Jeanne Bowen Nix. 7. Does not include 5,000,000 shares subject to an option agreement between Mr. Nix and Mr. & Mrs. Belote such that Mr. Nix has the option to purchase these shares not before June 1, 2004 and not after March 31, 2005. 8. Includes 167,832 shares issued to Mr. Belote as payment for accrued salary between October 2003 and March 2004. All of the above individuals disclaim any beneficial ownership in shares owned by family members. -49- Item 12. Certain Relationships and Related Transactions On February 26, 2003, NCC acquired mining equipment and certain other intangible mining rights and information from Strata Coal, LLC ("Strata") for $47,000 ($7,000 cash and a non-interest bearing promissory note) and assumption of promissory notes payable to unrelated parties totaling $174,000. The Company also assumed $14,875 of Strata accounts payable. Strata is owned by the Chairman of the Board and the President/CEO of NCC. Since the Strata transaction involved related parties, primarily for intangible consideration, the $205,875 purchase price (exclusive of the mining equipment subsequently sold - see below), has been expensed. Subsequent to March 31, 2003 the promissory notes (totaling $214,000) have been paid, and on June 11, 2003, the mining equipment was sold to Jenco Capital Corporation ("Jenco") for $30,000. The CEO/President of NCC is also a stockholder of Jenco. In February 2003, the Company borrowed $150,000 from a trust owned by the Chairman of the Board. This note accrues simple interest at an annual rate of 8% and was to mature in February 2005. In August 2003, the Company and the Chairman agreed to extend the maturity date of such note for three additional years. The new maturity date is now February 20, 2008. No additional compensation was paid to the Chairman for such maturity extension. The note is classified as a current liability in the balance sheet due to the related party nature of the obligation. On March 31, 2003, the Company paid the Chairman of the Board and the CEO/President $150,000 each for organization, development and promotion activities to get the Company started. On July 1, 2003, the Company sold mineral royalty rights for coal mined on the Patterson Mountain portion of the New River Tract for $75,156 to Jenco, an entity partially owned by the CEO/President of the Company. As consideration for the $75,156 received, the Company is obligated to pay Jenco $2.00 per mined ton on the property. During the six months ended December 31, 2003, the Company paid Jenco $59,572 in accordance with this transaction. On August 1, 2003, the Company sold its interest in mineral royalty rights received by the Company from U.S. Coal, Inc. for coal mined on the Smokey Mountain portion of the New River Tract. The royalty was sold for $250,000 to Jenco. As consideration for the $250,000 received, Jenco began receiving the royalty payments from U.S. Coal. The Company recorded the transaction as deferred revenue and recognizes revenue each month based on U.S. Coal's production. As of December 31, 2003, royalties totaling $146,597 have been recognized, leaving $103,403, which is included in deferred revenue. These transactions were completed by the Company with Jenco Capital Corporation, a related party, because (i) the Company needed a prompt capital infusion to ramp up coal production, (ii) Jenco had available cash for the transaction, (iii) the Company could not have developed another independent source for the capital without considerable time delay due to lack of a production history, and (iv) the Company had no knowledge of any outside sources for such capital. The Company believes that given the time delay to search for capital and the cost of lost opportunity, the terms of these transactions were acceptable because it afforded immediate liquidity for operating purposes. On June 30, 2003, the Board of Directors assigned a ten-year, $0.25 per ton royalty interest on all the coal sold from the New River Tract, to both the Chairman of the Board and the CEO/President. In the event any mineral properties are sold prior to end of the ten-year period, the obligation is to be settled by paying 12 1/2% of the sales price to each individual. Pursuant to the sale of mineral property rights to Jenco Capital Corporation (see two paragraphs above), the Company has recorded a liability to pay both the Chairman of the Board and the President 12 1/2% of the sales price, a total of $81,289. In February 2004, the President/CEO and Chairman of the Board each agreed to permanently cancel all future royalty payments, which were to be made to each of them by the Company pursuant to the June 30, 2003 agreement. -50- In August 2003, the Company borrowed $250,000, in October 2003, the Company borrowed $25,000, and in December 2003, the Company borrowed $30,000, from Jenco. In December 2003, the Company borrowed $105,000 from the CEO/President of the Company. The notes payable accrue simple interest at an annual rate of 8% and are payable on demand. In October 2003, the Company loaned the Chief Financial Officer $15,000 at an annual interest rate of 3 1/2% and a maturity of 1 year. This loan was made during the period of time that the CFO was performing his duties on an interim basis and was not considered an officer of the Company. In February 2004, this loan, plus accrued interest, was paid in full. During 2003, the Company paid the law firm of Kite, Bowen & Associates, PA a total of $45,000 for professional services rendered. Mr. Kite is the owner of Kite, Bowen & Associates, PA, and is a director of the Company. In January 2004, the Company borrowed $10,000 from Jenco. The note payable accrues simple interest at an annual rate of 8% and is payable on demand. In February 2004, the Company repaid (i) $105,000 in principal and $1,024 in accrued interest to the CEO/President of the Company, and (ii) $65,000 in principal and $998 in accrued interest to Jenco. In February 2004, four unrelated parties, holding an aggregate principal amount of $198,000 of notes payable, accepted an offer from the Company to convert all of their then outstanding principal and accrued interest into common shares of the Company at a conversion price of $0.55 per share. Consequently, the Company issued 368,399 shares collectively of its common stock, with 360,000 representing the conversion of principal due, and 8,399 representing accrued interest. In February 2004, Crestview Capital Master, LLC ("Crestview"), an entity controlled by Crestview Capital Funds, directly purchased four outstanding notes payable debt of the Company, from an unrelated party, in the aggregate principal amount of $3,465,200, plus unpaid interest. Concurrent with the repurchase of this debt, Crestview agreed to extend the maturity date on all four notes to March 25, 2005 and to modify certain provisions. The interest rate remains at 12% per annum. Two of the original notes, in the aggregate principal amount of approximately $3.2 million, each of which had a conversion option into common shares of the Company at a conversion price of $0.50 per share, have been modified to preclude conversion if the issuance would cause Crestview to own more that 9.99% of the then outstanding equity in the Company when computed in accordance with Section 13d of the Securities and Exchange Act of 1934. Crestview also purchased warrants from the debt holder, which had been concurrently issued with the original two notes. Those warrants allow for Crestview to purchase 1,597,250 shares of common stock at a price per share equal to $0.55 until March 25, 2005. In March 2004, the Chairman agreed to reduce his annual base salary to $36,000. This agreement was entered into as a result of the Chairman taking a much less active role in the day-to-day operations of the Company. Concurrent with this reduction in annual base salary, the Chairman, who had been accruing his salary since October 2003, agreed to receive all previously accrued salary in stock, using a price per share of $0.55. This resulted in the issuance of 167,832 shares to the Chairman in March 2004. -51- Item 13. Exhibits, List and Reports on Form 8-K (a) Exhibits: The following exhibits are filed as part of this report: 31.1 Certification pursuant to Section 302 of the Sarbanes Oxley Act of 2003 (Jon Nix) 31.2 Certification pursuant to Section 302 of the Sarbanes Oxley Act of 2003 (Robert Chmiel) 32.1 Certification of Disclosure pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (b) Reports on Form 8-K. Index of Exhibits 3.1 Articles of Incorporation (*) 3.2 Bylaws (*) 3.3 Articles of Amendment (*) 10.1 Share Purchase Agreement (*) 10.2 Plan & Agreement of Reorganization (*) 10.3 Webb Group Note (*) 10.4 Modified Note for $1,691,885 (*) 10.5 Note for 75,000 (*) 10.6 Note for 195,314 (*) 10.7 Warrant to Webb Group for 751,500 shares* 10.8 Warrant to Webb Group for 845,750 shares* 10.9 Warrant Modification for 845,750 shares* 10.10 Warrant Modification for 751,500 shares* 23.1 Consent of gordon, Hughes & Banks, LLP. (*) - Incorporated by reference to filings made pursuant to Section 13 of the Securities & Exchange Act of 1934. (b) Reports on Form 8-K. 8K 12G3 December 18, 2003 8K August 7, 2003 8K April 24, 2003 Item 14. Principle Accounting Fees and Services General. Gordon, Hughes & Banks, LLP is the Company's principal independent auditing accounting firm (the "Auditors"). The Company's Board of Directors has considered whether the provisions of the audit services are compatible with maintaining the independence of its Auditors. Gordon, Hughes & Banks provides only auditing and tax preparation functions and no other services to the Company. -52- Audit Fees. Gordon, Hughes & Banks, LLP billed the Company $34,300 for the following professional services: audit of the annual financial statement of the Company for the fiscal year ended December 31, 2003, and reviews of the interim financial statements included in quarterly reports on Form 10-QSB for the periods ended June 30, 2003, and September 30, 2003. Gordon, Hughes & Banks billed the Company $18,800 for the audit dated March 31, 2003. There were no tax fees paid to Gordon, Hughes & Banks in 2002 or 2003, however in 2003, the Company did pay $2,600 related to the review of a private placement memorandum used by the Company to raise capital. The Company's Board acts as the Audit Committee and had no "pre-approval policies and procedures" in effect for the auditors' engagement for the audit years 2002 and 2003. No fees other than Audit Fees were incurred or approved by the Board. All audit work was performed by the full time employees of the Auditors. -53- SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. NATIONAL COAL CORPORATION Date: December 15, 2004 /s/ Robert Chmiel ---------------------------- By: Robert Chmiel Its: Chief Financial Officer (Principal Financial and Accounting Officer) Directors: /s/ Jon Nix ---------------------------- Jon Nix ---------------------------- Farrald Belote /s/ Robert Chmiel ---------------------------- Robert Chmiel -54- INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Page ---- I. Report of Independent Public Accountants F-1 II. Financial Statements: Consolidated Balance Sheet at December 31, 2003 F-2 Consolidated Statement of Operations for the Eleven Months Ended December 31, 2003 F-3 Consolidated Statement of Cash Flows for the Eleven Months Ended December 31, 2003 F-4 Condensed Consolidated Statement of Changes in Stockholders' Deficiency Inception (January 30, 2003) to December 31, 2003 F-5 Notes to the Consolidated Financial Statements F-6 to F-19 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors National Coal Corporation Knoxville, Tennessee We have audited the consolidated balance sheet of NATIONAL COAL CORPORATION as of December 31, 2003, and the related consolidated statements of operations, cash flows and changes in stockholders' deficiency for the period from its inception (January 30, 2003) to December 31, 2003. 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 audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. 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 audit provides a reasonable basis for our opinion. In our opinion, the accompanying consolidated financial statements referred to above present fairly, in all material respects, the financial position of NATIONAL COAL CORPORATION at December 31, 2003, and the results of its operations and its cash flows for the period from its inception to December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company's significant operating losses, working capital deficit and stockholders' deficiency raise substantial doubt about its ability to continue as a going concern. The financial statements do not include any adjustments that might result from the outcome of this uncertainty. /s/Gordon, Hughes & Banks Greenwood Village, Colorado February 13, 2004 F-1
NATIONAL COAL CORPORATION CONSOLIDATED BALANCE SHEET December 31, 2003 ASSETS Current Assets: Cash and cash equivalents $ 883 Accounts receivable 4,327 Inventory 145,863 Prepaid and other 30,197 ---------------- Total current assets 181,270 ---------------- Property and Equipment: Mining equipment 1,057,566 Computer equipment and software 79,969 Automobile and mobile equipment 61,232 Office equipment and furniture 25,611 ---------------- 1,224,378 Less: accumulated depreciation (240,440) ---------------- Property and Equipment, net 983,938 ---------------- 1,362,190 Coal and Mineral Rights, net of $3,040 accumulated depletion 1,362,190 Reclamation Bond 257,500 Loan acquisition costs, less accumulated amortization of $366,628 45,607 ---------------- Total Assets $ 2,830,505 ================ LIABILITIES AND STOCKHOLDERS' DEFICIENCY Current Liabilities: Notes payable $ 3,663,217 Notes payable to related parties 560,000 Capital lease obligations 458,803 Accrued royalty payable to officers 81,289 Accounts payable and accrued expenses, other than payroll related expenses 469,005 Accrued payroll, including payroll taxes 180,154 Accrued interest payable 101,597 Deferred revenue 179,050 ---------------- Total current liabilities 5,693,115 Accrued Reclamation Expenses 64,359 ---------------- Total Liabilities 5,757,474 ---------------- Stockholders' Deficiency: Preferred stock, $.0001 par value; 10 million shares authorized; none issued and outstanding - Common stock, $.0001 par value; 80 million shares authorized; 37,015,931 issued and outstanding 3,702 Additional paid-in capital 402,214 Accumulated deficit (3,332,885) ---------------- Total Stockholders' Deficiency (2,926,969) ---------------- Total Liabilities and Stockholders' Deficiency $ 2,830,505 ================ See Notes to Consolidated Financial Statements.
F-2 NATIONAL COAL CORPORATION CONSOLIDATED STATEMENT OF OPERATIONS Eleven Months Ended December 31, 2003 REVENUES Coal sales $ 1,012,520 Royalties 178,123 --------- Total revenue 1,190,643 EXPENSES Cost of mine operations and selling expenses 1,657,570 General and administrative 1,871,414 Exploration and development 80,367 Depreciation, depletion and accretion 250,527 Amortization 366,628 --------- Total operating expenses 4,226,506 --------- LOSS FROM OPERATIONS (3,035,863) ---------- OTHER INCOME (EXPENSE) Gain on sale of marketable securities 73,825 Other income 1,612 Interest expense (372,459) ---------- Total other income (expense) (297,022) ---------- NET (LOSS) $(3,332,885) ========== BASIC AND DILUTED NET (LOSS) PER SHARE $ (0.09) ========== WEIGHTED AVERAGE COMMON SHARES 36,550,518 ========== See Notes to Consolidated Financial Statements. F-3
NATIONAL COAL CORPORATION CONSOLIDATED STATEMENT OF CASH FLOW Eleven Months Ended December 31, 2003 CASH FLOWS FROM OPERATING ACTIVITIES Net (loss) $ (3,332,885) Adjustments to reconcile net (loss) to net cash provided by operating activities Depreciation and depletion 243,480 Amortization 366,628 Accretion of accrued reclamation expenses 7,047 Stock issued for services 153,500 Non-cash compensation 191,000 Changes in operating assets and liabilities: Receivables (4,327) Inventory (145,863) Prepaid and other (30,197) Accounts payable and accrued liabilities 831,158 Deferred revenue 179,050 ----------- Net cash flows provided (to) operating activities (1,541,409) ----------- CASH FLOWS FROM INVESTING ACTIVITIES Reclamation bond (257,500) Acquisition of coal and mineral rights (1,307,917) Equipment and vehicles purchased (448,462) Sale of mining equipment to related party 23,000 ------------ Net cash flows provided from (to) investing activities (1,990,879) ------------ CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from issuance of convertible debt, less acquisition costs 2,782,667 Proceeds from issuance of debt 467,689 Proceeds from issuance of related party debt 560,000 Payment of notes payable (226,500) Payments on capital leases (317,112) Proceeds from issuance of common stock 287,500 Repurchase and cancellation of common stock (21,073) ------------ Net cash flows provided from (to) financing activities 3,533,171 ------------ NET INCREASE IN CASH 883 CASH AND EQUIVALENTS, BEGINNING OF PERIOD - ------------ CASH AND EQUIVALENTS, END OF PERIOD $ 883 ============ SUPPLEMENTAL DISCLOSURES Interest paid $ 270,862 Income taxes paid - Non-cash investing and financing transactions: Net liabilities of Southern Group International, Inc. at the date of reverse merger 14,012 Capital lease obligations to acquire mining equipment 775,916 Recognition of accrued reclamation expenses 57,312 Assumption of promissory notes from Strata Coal, LLC: Charged to operations 191,000 Partial payment of mining equipment 23,000 See Notes to Consolidated Financial Statements. F-5
NATIONAL COAL CORPORATION CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' DEFICIENCY Common Stock Additional -------------------------------------------------- NCC SGI Paid- In Accumulated -------------------------------------------------- Shares Amount Shares Amount Capital Deficit Total ------ ------ ------ ------ ------- ------- ----- Inception, January 30, 2003 - $- - $- $- $- $- Issuance of stock for services 15,350,000 153,500 - - - - 153,500 Sale of stock for cash 1,750,000 17,500 - - - - 17,500 Reorganization April 2003: Net liabilities of SGI - - 1,887,381 189 177,034 (191,235) (14,012) Issuance of SGI shares to NCC shareholders (17,100,000) (171,000) 34,200,000 3,420 (23,655) 191,235 - Sale of stock for cash - - 1,350,000 135 269,865 - 270,000 Repurchase and cancellation - - (421,450) (42) (21,030) - (21,072) Net (loss) - - - - - (3,332,885) (3,332,885) ------------- --------- ---------- ------- -------- ------------ ------------ Balance, December 31, 2003 - $ - 37,015,931 $ 3,702 $402,214 ($3,332,885) ($2,926,969) ============= ========= ========== ======= ======== ============ ============ See Notes to Consolidated Financial Statements. F-6
1. Business and Basis of Presentation National Coal Corporation was incorporated in Tennessee on January 30, 2003. On March 28, 2003, National Coal Corporation entered into a Share Purchase Agreement whereby it purchased from an unrelated individual, 500,000 shares, or 22%, of Southern Group International, Inc. ("SGI"), a company incorporated in the State of Florida on August 10, 1995. These 500,000 shares were cancelled on April 11, 2003, when the Board of Directors of SGI approved an Agreement and Plan of Reorganization whereby all the outstanding shares of National Coal Corporation were exchanged on April 30, 2003 for 34,200,000 shares of Southern Group International, Inc. See Footnote #6. Articles of Amendment to the Articles of Incorporation were filed in with the Secretary of State's Office in Florida on August 4, 2003 changing the name of Southern Group International, Inc. to National Coal Corporation ("NCC", "National Coal" or the "Company" hereafter). National Coal Corporation (Tennessee) operates as a wholly owned subsidiary of National Coal Corporation, a Florida corporation. The Company was inactive prior to the acquisition of National Coal Corporation (Tennessee) in April 2003. The principal activity of the Company is coal mining. The Company currently owns, in fee simple, the coal mineral rights to the New River Tract assemblage, which consists of approximately sixty-five thousand (65,000) acres that lie in Anderson, Campbell and Scott Counties, approximately twenty-five miles northwest of Knoxville, Tennessee. These mineral rights revert back to the surface owner on June 5, 2093. At the present time there are two separate areas located on the New River Tract assemblage that are producing coal which include (1) a surface mine situated in Devonia, Tennessee (Patterson Mountain), and (2) a portion of the New River Tract mined by U.S. Coal, Inc., an independent mine operator that pays royalties to the Company on its' coal production. The Company engages in coal production by locating, assembling, leasing, assessing, permitting and developing coal properties in Eastern Tennessee. The Company, after obtaining permits from the U.S. Department of the Interior, mines said properties or contracts with independent mine operators for extraction of the coal minerals on a negotiated fee basis. Some contracts may be on a per ton basis, and some may be on a cost plus basis. The variance is usually due to varying extraction conditions and circumstances. Reclamation bonds are obtained and maintained by the Company for each producing property. Bonds typically take the form of cash deposits with the U.S. Department of the Interior, Office of Surface Mining. In theory, insurance bonds could be used, but such are extremely difficult and time consuming for small companies to obtain in the market. The Company currently sells its' production into the spot market and/or based on short-term contracts, but in the future intends to seek long-term supply contracts. No such long-term contracts have been negotiated to date. Many of the Company's properties have been subject to limited production in the past. Some of the properties were abandoned by previous producers due to poor market conditions, uneconomical production, high labor costs and/or reclamation bond difficulties. The Company maintains an umbrella liability insurance policy for all of its operations, and requires liability policies to be furnished by contract operators, naming the Company as a co-insured. The coal industry has been highly competitive with very thin margins in recent years. Only in the past two years, in the opinion of management, have the economics begun to look favorable for coal again. This situation is due to, among other things, the surge in prices of natural gas. The price increases of natural gas, on a Btu basis, have reached the point that coal fired power plants, using the latest clean air compliant scrubber technology, can be price competitive with natural gas fired plants. F-7 The Company intends to exploit its mineral rights by opening mines, as its capital will allow, but it can only open a mine with an estimated $500,000 to $750,000 per mine, including bonds or cash deposited. Due to the operating capital constraints, if the Company cannot raise such needed additional amounts by loans or private placements, it will prevent the Company from expanding its mining operations beyond the current operations. Since the formation of National Coal Corporation on January 30, 2003, it had been deemed to be in the exploration stage because the Company did not have any direct coal mining operations or proven reserves. However, during the three-month period ended September 30, 2003, production commenced and accordingly, the Company is no longer considered to be in the exploration stage. Going Concern Uncertainty The accompanying audited consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. The carrying amounts of assets and liabilities presented in the financial statements do not purport to represent realizable or settlement values. No operations were conducted and no operating revenue was realized from January 30, 2003 to June 30, 2003, and the Company only began mining operations thereafter. As of December 31, 2003, the Company was totally illiquid and needed cash infusions from shareholders to provide capital, or needed loans from any source available. At December 31, 2003, the Company had negative working capital of approximately $5,512,000 and a stockholders' deficiency of approximately $2,927,000. These factors raise substantial doubt about the Company's ability to continue as a going concern. The Company is seeking additional funding and believes that this will result in improved operating results. There can be no assurance, however, that the Company will be able to secure additional funding, or that if such funding is available, whether the terms or conditions would be acceptable to the Company. 2. Summary of Significant Accounting Policies Principles of Consolidation The accompanying financial statements include the accounts of National Coal Corporation (Tennessee) from its' inception and of SGI since the April 2003 merger. All intercompany transactions and balances from the date of the merger have been eliminated in consolidation. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that materially affect the amounts reported in the financial statements and accompanying notes. Actual results could materially differ from those estimates. Revenue Recognition Under SEC Staff Accounting Bulletin No. 101, "Revenue Recognition in Financial Statements," the Company recognizes revenue when all of the following criteria are met: (1) persuasive evidence of an arrangement exists, (2) delivery has occurred or services have been rendered, (3) the seller's price to the buyer is fixed or determinable, and (4) collectibility is reasonably assured. In the case of the Company's product, a price is negotiated with each customer with specifics for requirements, a fixed price per ton, a delivery schedule, and terms for payment. Unless cash is paid in advance, accounts receivables are recorded as revenue is earned. The Company regularly evaluates the collectibility of its' receivables based on a combination of factors. To date, the Company has not had any customer whose payment was considered past due, and as such has not had to record any reserves for doubtful collectibility. F-8 Coal Sales The Company currently sells its' coal in raw form (i.e. the coal has not been processed, washed or cleaned in any manner), on a per ton basis. Sales typically are through a third party broker and the Company pays a commission (on a per ton basis) to the broker. Brokered sales are typically to state utility companies. The Company also sells direct to other coal producers, as well as direct to consumers. Each sale is made at a negotiated price. The price charged is typically for a specified tonnage amount, referred herein as a "contract price." Sales are also priced on a one-day or one-shipment tonnage amount. The price per ton for these types of sales typically fluctuates in direct correlation to the price per ton of coal quoted on the New York Mercantile Exchange, referred to as the "spot price." All of the Company's sales are for short-term contracts (i.e. the amount of tonnage committed to be sold can typically be delivered in less than two weeks). The Company recognizes revenue from coal sales at the time title passes to the customer, which generally takes place near the Company's mine site. The Company does not provide or arrange for transportation of coal and therefore, "pass through" shipping costs are not included in either coal sales or the cost of mining operations and selling expenses. Royalties During the eleven-month period from inception (January 30, 2003) to December 31, 2003, the Company recorded royalties for coal mined by U.S. Coal, Inc. on a portion of the New River Tract. In August 2003, this royalty right was sold for $250,000 to Jenco Capital Corporation, an entity partially owned by the CEO/President of the Company (see Footnote #7). At December 31, 2003, $103,403 of the amount of the royalty sold to Jenco was recorded as deferred revenue, pending future production by U.S. Coal, Inc. The Company expects to recognize this remaining revenue deferral during the first six months of 2004. Cost of Mining Operations and Selling Expenses Cost of mining operations and selling expenses consists primarily of direct compensation and benefits cost for miners, as well as direct costs such as equipment lease and maintenance, blasting, fuel, parts, hauling costs, and commissions paid to third party brokers. Exploration Costs Costs related to locating coal deposits and determining the economic mineability of such deposits are expensed as incurred. Compensation The Company accounts for stock-based compensation using Accounting Principles Board's Opinion ("APB") No. 25, "Accounting for Stock Issued to Employees". Under APB No. 25, compensation expense is recognized for stock options with an exercise price that is less than the market price on the grant date of the option. For stock options granted employees or directors with exercise prices at or above the market value of the stock on the grant date, the Company has adopted the Financial Accounting Standards Board ("FASB") disclosure-only provisions of Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"). As of December 31, 2003, the Company did not have any employee stock-based compensation programs. However, in February 2004 a stock option plan was presented to shareholders for approval. See Footnote #9. F-9 Comprehensive Income There are no adjustments necessary to the net loss as presented in the accompanying statement of operations to derive comprehensive income in accordance with Statement of Financial Standards ("SFAS") No. 130, "Reporting Comprehensive Income." Segment Reporting In June 1997, SFAS 131, "Disclosure about Segments of an Enterprise and Related Information," was issued. Operating segments, as defined in the pronouncement, are components of an enterprise about which separate financial information is available and that are evaluated regularly by management in deciding how to allocate resources and assess performance. As of December 31, 2003, the Company had one operating segment, coal mining. Cash and Cash Equivalents Cash and cash equivalents are stated at cost. Cash equivalents consist of all highly liquid investments with maturities of three months or less when acquired. Marketable Securities The Company has adopted SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities," in accounting for securities. During 2003, the Company completely liquidated its' investment portfolio and recognized a net gain on sales of marketable securities totaling $73,825. Inventory Inventory consists of extracted coal available for delivery to customers, and is valued at the lower of average cost or market. Coal inventory costs include labor, supplies, equipment costs and operating overhead. Property and Equipment Property and equipment are stated at cost. Expenditures for significant renewals and improvements that extend estimated lives are capitalized. Replacements, maintenance and repairs, which do not improve or extend the life of the respective asset, are expensed as incurred. The Company removes the cost and the related accumulated depreciation from the accounts for assets sold or retired, and the resulting gains or losses are included in the results of operations. Leased property and equipment meeting certain criteria is capitalized and the present value of the related lease payments is recorded as a liability. Depreciation is provided using the straight-line method over the estimated useful lives or lease life of the assets, ranging up to five years; expense recorded for the eleven months ended December 31, 2003 was $240,440. F-10 Coal and Mineral Rights Significant expenditures incurred to acquire coal and mineral rights are capitalized at cost. These costs represent the investment in mineral rights, including capitalized mine development costs, which are being mined or will be mined. Depletion and amortization is computed on an actual tonnage mined basis calculated to amortize costs fully, based on estimated total tonnage to be mined. Reclamation The Company has adopted the provisions of SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 generally applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation of a long-lived asset. SFAS No. 143 requires recognition of expenses for eventual reclamation of disturbed acreage remaining after mining production has been completed. A liability is recorded for the present value of reclamation and mine closing costs with a corresponding increase in the carrying value of coal and mineral rights at the time a mine is permitted and commences operations. The carrying costs are amortized and accrued expenditures accreted (in connection with increases in the discounted liability) based on production from the mine proportionate to the estimated total tonnage to be mined. Loan Acquisition Costs Loan acquisition costs, related to convertible notes payable, are being amortized using the straight-line method over the twelve-month term of the debt. Asset Impairment If facts and circumstances suggest that a long-lived asset may be impaired, the carrying value is reviewed. If this review indicates that the value of the asset will not be recoverable, as determined based on projected undiscounted cash flows related to the asset over its' remaining life, then the carrying value of the asset is reduced to its estimated fair value. Fair Value of Financial Instruments The carrying amounts for cash, accounts receivable, accounts payable and accrued liabilities approximate fair value because of their immediate or short-term maturities. The fair value of notes payable approximates fair value because of the market rate of interest on the debt. Income Taxes Deferred income taxes are based on temporary differences between the financial statement and tax basis of assets and liabilities existing at each balance sheet date using enacted tax rates for years during which taxes are expected to be paid or recovered. Net Loss Per Share The Company computes and presents loss per share in accordance with SFAS No. 128, "Earnings Per Share". Basic earnings per share are computed based upon the weighted average number of common shares outstanding during the period. Warrants and convertible debt representing common shares of 1,597,250 and 6,520,022, respectively, were excluded from the average number of common shares outstanding in the calculation because the effect of inclusion would be anti-dilutive. F-11 All per share amounts reflect the retroactive effect of the April 2003 merger - See Footnote #6. A summary of weighted average shares follows: 11 Months Ended December 31, 2003 Shares Outstanding January 30, 2003 - SGI 2,228,931 NCC 34,200,000 Purchase of shares (500,000) February 15, 2003 - Conversion of account payable 150,876 June 17, 2003 - Purchase of shares (247,855) June 30, 2003 - Sale of shares 288,383 July 7, 2003 - Sale of shares 290,620 July 14, 2003 - Sale of shares 139,563 ------------ Total 36,550,518 ============ Concentration of Credit Risk and Major Customers SFAS No. 105, "Disclosure of Information about Financial Instruments with Off-Balance-Sheet Risk and Financial Instruments with Concentrations of Credit Risk", requires disclosure of significant concentration of credit risk regardless of the degree of such risk. Financial instruments, which potentially subject the Company to concentrations of credit risk, consist primarily of cash and accounts receivable. Accounts receivable are from brokers or purchasers of the Company's coal. The Company routinely performs credit evaluations of customers purchasing on account and generally does not require collateral. The Company maintains the majority of its' cash deposits in one bank. The deposits are guaranteed by the Federal Deposit Insurance Corporation ("FDIC") up to $100,000. At December 31, 2003, the Company's cash balance at the bank was not in excess of the FDIC insurance limit. During 2003, the Company derived approximately 93% of total coal sales from three customers. Recent Accounting Pronouncements In June 2002, the Financial Accounting Standards Board ("FASB") issued SFAS No.146, "Accounting for Costs Associated with Exit or Disposal Activities". SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity". SFAS No. 146 generally requires a liability for a cost associated with an exit or disposal activity to be recognized and measured initially at its fair value in the period in which the liability is incurred. The pronouncement is effective for exit or disposal activities initiated after December 31, 2002. The Company does not believe that the adoption of SFAS No. 146 will have any impact on its' financial position or results of operations. F-12 SFAS No. 147, "Acquisitions of Certain Financial Institutions," was issued in December 2002 and is not expected to apply to the Company's current or planned activities. In December 2002, the FASB approved SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure - an amendment of FASB Statement No. 123". SFAS No. 148 amends SFAS No. 123, "Accounting for Stock-Based Compensation" to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. SFAS No. 148 is effective for financial statements for fiscal years ending after December 15, 2002. The Company will continue to account for stock based compensation using the methods detailed in its' stock-based compensation accounting policy. In April 2003, the FASB approved SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities". SFAS No. 149 is not expected to apply to the Company's current or planned activities. In June 2003, the FASB approved SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity". SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. This Statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. SFAS No. 150 is not expected to have an effect on the Company's financial position. In December 2003, the FASB issued a revised Interpretation No. 46, "Consolidation of Variable Interest Entities". The interpretation clarifies the application of Accounting Research Bulletin No. 51, "Consolidated Financial Statements", to certain types of entities. The Company does not expect the adoption of this interpretation to have any impact on its' financial statements. 3. Lease Commitments During the second calendar quarter, the Company entered into short-term capital lease agreements to acquire four mining vehicles with a combined estimated fair value of $775,916, which approximates the present value of the minimum lease payments. Amortization is included in depreciation expense. Additionally, the Company rents other mining equipment pursuant to operating lease agreements, and made lease payments totaling $307,478 during 2003. In March 2003, the Company agreed to lease space in Georgia, on a month-to-month basis, at $600 per month. In April 2003, the Company entered into an agreement to lease its' Knoxville office for nine months at $1,800 per month, with an option to renew for an additional nine months. Rental expense for these lease commitments totaled approximately $22,200 through December 31, 2003. F-13 A summary of future minimum payments under non-cancelable capital and operating lease agreements as of December 31, 2003 follows: Year Ending Operating December 31, Capital Leases Leases Total ------------ -------------- ------ ----- 2004 $ 476,000 $ 138,000 $ 614,000 2005 - - - Total minimum lease payments 476,000 138,000 614,000 Less imputed interest (17,197) - (17,197) ------- ------- -------- PV of minimum lease payments $ 458,803 $ 138,000 $ 596,803 ======= ======= ======== 4. Notes Payable In February 2003, the Company borrowed $150,000 from a trust owned by the Chairman of the Board of the Company. This note accrues simple interest at an annual rate of 8% and was to mature in February 2005. In August 2003, the Company and Chairman agreed to extend the maturity date of such note for three additional years. The new maturity date is now February 20, 2008. No additional compensation was paid to the Chairman for such maturity extension. The note is classified as a current liability in the accompanying balance sheet due to the related party nature of the obligation. In March 2003, the Company issued convertible notes in the principal amount of $3,194,902 to an unrelated party. These notes and related accrued interest are convertible into common stock at $0.50 per share. In addition, the note holder received warrants to purchase 1,597,250 shares of common stock at $0.55 per share for two years. In September 2003, the Company borrowed $75,000 and $195,315 from the same entity. All of the notes payable accrue simple interest at an annual rate of 12%, mature in March 2004, and have terms that require an earlier payoff in the event of a successful equity or debt capital financing. As of December 31, 2003, the four notes totaled approximately $3,465,200, exclusive of accrued interest. In February 2004, these notes were acquired by another investor and the maturity extended to March 2005. See Footnote #9. In August 2003, the Company borrowed $250,000, in October 2003, the Company borrowed $25,000, and in December 2003, the Company borrowed $30,000, from Jenco Capital Corporation ("Jenco"), an entity partially owned by the CEO/President of the Company. In December 2003, the Company borrowed $105,000 from the CEO/President of the Company. The notes payable accrue simple interest at an annual rate of 8% and are payable on demand. In September 2003, the Company borrowed $80,000 from two unrelated parties. The related notes payable accrue simple interest at an annual rate of 10%, mature in March 2004, and have terms that require an earlier payoff in the event of a successful equity or debt capital financing. In November 2003, the Company renegotiated the terms of indebtedness with these two unrelated parties, such that the maturity was extended to March 7, 2004. As consideration for the maturity extension, the principal amount payable to each note holder was increased 10% and detachable warrants to purchase a total of 73,333 shares of common stock at $.60 per share for two years. Specifically, one holder's principal amount, which was originally due on October 15, 2003, was increased from $30,000 to $33,000 as a result of the extension, and the other holder's principal amount, which was originally due on November 11, 2003, was increased from $50,000 to $55,000 as a result of the extension. The notes and related accrued interest were converted into common stock in February 2004 at a conversion rate of $0.55 per share. See Footnote #9. F-14 In November 2003, the Company borrowed $110,000 from two unrelated parties. The related notes payable accrue simple interest at an annual rate of 10%, mature in March 2004, and have terms that require an earlier payoff in the event of a successful equity or debt capital financing. The note holders were also issued detachable warrants to purchase a total of 91,667 shares of common stock at $.60 per share for two years. The notes and related accrued interest were converted into common stock in February 2004 at a conversion rate of $0.55 per share. See Footnote #9. 5. Income Taxes At December 31, 2003, the Company had a net operating loss carryforward of approximately $3.3 million that may be offset against future taxable income through 2023. These carryforwards are subject to review by the Internal Revenue Service. The Company has fully reserved the $1.2 million tax benefit of the operating loss carryforward, by a valuation allowance of the same amount, because the likelihood of realization of the tax benefit cannot be determined. Temporary differences between the time of reporting certain items for financial statement and tax reporting purposes consists primarily of depreciation, depletion and accrued reclamation expenses. 6. Equity Transactions On March 28, 2003, National Coal Corporation (Tennessee) entered into an Agreement and Plan of Reorganization to acquire 34.2 million shares of Southern Group International, Inc. common stock for all of National Coal Corporation (Tennessee)'s outstanding common stock and $50,000 to retire 500,000 shares of SGI common stock. The $50,000 payment was made in March 2003 and recorded as an administrative expense. The shares were exchanged on April 30, 2003. Immediately after the transaction, the former National Coal Corporation (Tennessee) shareholders owned approximately 94.8% of SGI's common stock. Coincident with the transaction, SGI changed its' name to National Coal Corporation. The reorganization was recorded as a recapitalization effected by a reverse merger wherein NCC/SGI is treated as the acquiree for accounting purposes, even though it is the legal acquirer. Since SGI was a non-operating entity with limited business activity, goodwill was not recorded. An unaudited pro-forma summary of consolidated net liabilities on March 31, 2003 is set forth below:
NCC (Tennessee) NCC/SGI Consolidated Cash and equivalents $1,220,798 $ 227 $ 1,221,025 Other current assets 5,000 - 5,000 Other assets 1,736,510 - 1,736,510 Notes payable and - current liabilities (3,585,766) (13,922) (3,599,688) ------------- ---------- ---------- Net liabilities $ (623,458) $(13,695) $ (637,153) =========== ========= ===========
The following unaudited pro forma consolidated results of operations for the twelve months ended March 31, 2003 and 2002 (which includes NCC (Tennessee) activity solely for the period since its inception to March 31, 2003) assumes the business combination had occurred April 1, 2001: Year Ended March 31, 2003 2002 ---- ---- Revenues $ -0- $ -0- ======= ====== Net income (loss) $(804,705) $(26,039) ========== ========= Net income (loss) per share* $ (.02) $ (.00) ========== ========= *Based on 1,887,381 NCC/SGI shares outstanding prior to the reverse merger and 34,200,000 NCC/SGI shares issued as a result of the merger. F-15 In management's opinion, the unaudited pro forma results of operations are not indicative of the actual results that would have occurred if the acquisition had taken place at the beginning of the periods presented and are not intended to be a projection of future results. Issuance of Stock for Services In January 2003, a total of 15,350,000 shares of common stock were granted to the four founding officer/directors of the Company for services. The stock was valued at $153,500 ($0.01 per share) based on stock transactions for cash with unrelated individuals (see below). Issuance of Stock for Cash In January and February 2003, a total of 1,750,000 shares of common stock were sold to individuals for $17,500 ($0.01 per share). In June and July 2003, a total of 1,350,000 shares were sold to investors for $270,000 ($0.20 per share). Convertible Debt and Warrants to Purchase Common Stock In March 2003, the Company issued two convertible notes payable for a total of $3,194,902. The notes and related accrued interest are convertible into common stock at $0.50 per share. The convertible note holders also received warrants to purchase a total of 1,597,250 shares of common stock at $0.55 per share for two years. As of December 31, 2003, none of the warrants had been exercised. See Footnotes #4 & #9. In November 2003, the Company issued four note payable holders warrants to purchase a total of 165,000 shares of common stock for two years at $.60 per share (see Footnote #4). In the estimation of management, the value of the warrants are not significant to the results of operations. As of December 31, 2003, none of the warrants have been exercised. Other In June 2003, 421,450 shares of SGI common stock were re-purchased for $21,073 and cancelled. 7. Related Party Transactions On July 1, 2003, the Company sold mineral royalty rights for coal mined on the Patterson Mountain portion of its' New River Tract for $75,156 to Jenco Capital Corporation ("Jenco"), an entity partially owned by the CEO/President of the Company. As consideration for the $75,156 received, the Company is obligated to pay Jenco $2.00 per mined ton on the property. During the six months ended December 31, 2003, the Company paid Jenco $59,572 in accordance with this transaction. On August 1, 2003, the Company sold its interest in mineral royalty rights received by the Company from U.S. Coal, Inc. for coal mined on the Smokey Mountain portion of the New River Tract. The royalty was sold for $250,000 to Jenco. As consideration for the $250,000 received, Jenco began receiving the royalty payments from U.S. Coal. The Company recorded the transaction as deferred revenue and recognizes revenue each month based on U.S. Coal's production. As of December 31, 2003, royalties totaling $146,597 have been recognized, leaving $103,403, which is included in deferred revenue. F-16 These transactions were completed by the Company with Jenco, a related party, because (i) the Company needed a prompt capital infusion to ramp up coal production, (ii) Jenco had available cash for the transaction, (iii) the Company could not have developed another independent source for the capital without considerable time delay due to lack of a production history, and (iv) the Company had no knowledge of any outside sources for such capital. The Company believes that given the time delay to search for capital and the cost of lost opportunity, the terms of these transactions were acceptable because it afforded immediate liquidity for operating purposes. On June 30, 2003, the Board of Directors assigned a ten-year, $0.25 per ton royalty interest on all the coal sold from the Company's New River Tract, to both the Chairman of the Board and the CEO/President. In the event any mineral properties are sold prior to the end of the ten-year period, the obligation is to be settled by paying 12 1/2% of the sales price to each individual. Pursuant to the sale of mineral property rights to Jenco (see two paragraphs above), the Company has recorded a liability to pay both the Chairman of the Board and the CEO/President 12 1/2% of the sales price, a total of $81,289. The obligations were paid in February 2004 and concurrently the June 30, 2003 agreements were canceled. See Footnote #9. On February 26, 2003, NCC acquired mining equipment and certain other intangible mining rights and information from Strata Coal, LLC ("Strata") for $47,000 ($7,000 cash and a non-interest bearing promissory note) and assumption of promissory notes payable to unrelated parties totaling $174,000. The Company also assumed $14,875 of Strata's accounts payable. Strata is owned by the Chairman of the Board and the CEO/President of NCC. Since the Strata transaction involved related parties, primarily for intangible consideration, the $205,875 purchase price (exclusive of the mining equipment subsequently sold -see below), has been expensed. Subsequent to March 31, 2003 the promissory notes (totaling $214,000) were paid and on June 11, 2003 the mining equipment was sold to Jenco for $30,000. On April 9, 2003, the Company acquired the coal mineral rights in fee simple to the New River Tract assemblage for $1,270,000. In connection with this transaction, the Company paid Kite, Bowen & Associates, PA $40,000 for legal services. Mr. Kite is the managing partner of Kite, Bowen & Associates, PA, and is a director of the Company. On March 31, 2003, the Company paid the Chairman of the Board and the CEO/President $150,000 each for corporate organization and promotion activities. In October 2003, the Company loaned the Chief Financial Officer $15,000 at an annual interest rate of 3 1/2% and a maturity of 1 year. This loan was made during the period of time that the CFO was performing his duties on an interim basis and was not considered an officer of the Company. In February 2004, this loan, plus accrued interest, was paid in full. During 2003, the Company paid the law firm of Kite, Bowen & Associates, PA a total of $45,000 for professional services rendered. 8. Accrued Reclamation Expense The Company's estimated reclamation expenses on its' Patterson Mountain Mine is based on engineering cost estimates developed by the U.S. Department of the Interior, Office of Surface Mining ("OSM") in connection with obtaining the mine permit. The obligation is discounted using an estimated credit-adjusted risk-free rate of 12% and an estimated mine life of 12.6 years. Revisions to estimated expenses could occur due to changes in future reclamation costs, useful mine life or if federal or state regulators enact new reclamation regulations. F-17 In the third quarter, 2003, the Company submitted the Patterson Mountain Mine permit application to the OSM and remitted $257,500 for a reclamation bond. On October 9, 2003, the OSM issued the permit to conduct surface mining and approved the reclamation bond. During 2003, the Company accrued Patterson Mountain Mine reclamation expenses as set forth below: ------------------------------------------------------ October 9, 2003 (issuance of permit) $ 57,312 ------------------------------------------------------ Obligations incurred - ------------------------------------------------------ Obligations settled - ------------------------------------------------------ Accretion expense 7,047 ------------------------------------------------------ Revision to estimates - ------------------------------------------------------ December 31, 2003 $ 64,359 ======== 9. Events Subsequent to December 31, 2003 Notes Payable Purchase and Extension of Convertible Notes In February 2004, Crestview Capital Master, LLC ("Crestview"), an entity controlled by Crestview Capital Funds, directly purchased four outstanding convertible notes payable of the Company, from an unrelated party, in the aggregate principal amount of approximately $3,465,200, plus unpaid interest. Concurrent with the repurchase of this debt, Crestview agreed to extend the maturity date on all four notes to March 25, 2005 and to modify certain provisions. The interest rate remains at 12% per annum. Two of the original notes, in the aggregate principal amount of approximately $3.2 million, each of which had a conversion option into common shares of the Company at a conversion price of $0.50 per share, have been modified to preclude conversion if the issuance would cause Crestview to own more that 9.99% of the then outstanding equity in the Company when computed in accordance with Section 13d of the Securities and Exchange Act of 1934. Crestview also purchased warrants from the debt holder, which had been concurrently issued with the original two notes. Those warrants allow for Crestview to purchase 1,597,250 shares of common stock at a price per share equal to $0.55 until March 25, 2005. Conversion of Notes Payable In January 2004, four unrelated parties, holding an aggregate principal amount of $198,000 of notes payable, accepted an offer from the Company to convert all of their then outstanding principal and accrued interest into common shares of the Company at a conversion price of $0.55 per share. Consequently, the Company issued 368,399 shares collectively of its' common stock, with 360,000 representing the conversion of principal due, and 8,399 representing accrued interest. Transactions with Related Parties In January 2004, the Company borrowed $10,000 from Jenco Capital Corporation, an entity partially owned by the CEO/President of the Company. The note payable accrues simple interest at an annual rate of 8% and is payable on demand. In February 2004, the Company repaid (i) $105,000 in principal and $1,024 in accrued interest to the CEO/President of the Company, and (ii) $65,000 in principal and $998 in accrued interest to Jenco. F-18 Sale of Equity In February 2004, the Company sold an aggregate of 5,000,000 shares of its common stock in a private placement, at a price per share of $0.55. The net proceeds to the Company were $2,750,000. Crestview Capital Master, LLC, an entity controlled by Crestview Capital Funds, purchased 2,600,000 of the 5,000,000 shares. This is Crestview's first investment with the Company. Three unrelated accredited individual investors purchased the remaining 2,400,000 shares. Cancellation of Royalty Agreements In February 2004, the Chairman of the Board and the CEO/President each agreed to permanently cancel all future royalty payments which were to be made to each of them by the Company pursuant to the June 30, 2003 ten-year, $0.25 per ton royalty interest agreement related to all the coal sold from the New River Tract. Stock Option Plan In February 2004, the Company sought and received the approval of its three largest shareholders, whose holdings collectively exceeded 80% of the then outstanding shares of the Company's common stock, to establish a stock option plan, to provide for the issuance of stock options to employees, consultants and vendors. Such Plan has not been implemented and the Information Statement thereon has not been distributed to Shareholders and the Plan is not yet effective. The stock option plan (the "Plan") will allow for the issuance of options to purchase up to an aggregate of 6 million shares of Company's common stock to be distributed pursuant to the rules and regulations of the Plan. To date, no options have been distributed out of the Plan. F-19 EX-23 2 ex23-1d.txt EX-23.1 EXHIBIT 23.1 CONSENT OF INDEPENDENT AUDITORS We consent to the incorporation of our report dated February 13, 2004, on the consolidated financial statements of NATIONAL COAL CORP. for the fiscal year ended December 31, 2003 into NATIONAL COAL CORP.'S previously filed Registration Statement on Form S-8 (File No. 333-115649). /s/ Gordon, Hughes & Banks, LLP ------------------------------- GORDON, HUGHES & BANKS, LLP Greenwood Village, Colorado December 15, 2004 EX-31 3 ex31-1g.txt EX-31.1 EXHIBIT 31.1 Certification of CEO Pursuant to Securities Exchange Act Rules 13a-14 and 15d-14 as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 I, Jon Nix, certify that: 1. I have reviewed this annual report on Form 10-KSB/A of National Coal Corp.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the small business issuer as of, and for, the periods presented in this report; 4. The small business issuer's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the small business issuer and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the small business issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Evaluated the effectiveness of the small business issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and c) Disclosed in this report any change in the small business issuer's internal control over financial reporting that occurred during the small business issuer's most recent fiscal quarter (the small business issuer's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the small business issuer's internal control over financial reporting; and 5. The small business issuer's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the small business issuer's auditors and the audit committee of the small business issuer's board of directors (or persons performing the equivalent function): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the small business issuer's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the small business issuer's internal control over financial reporting. Date: December 15, 2004 /s/ Jon Nix ------------------------------------- Jon Nix President and Chief Executive Officer EX-31 4 ex31-2g.txt EX-31.2 EXHIBIT 31.2 Certification of CFO Pursuant to Securities Exchange Act Rules 13a-14 and 15d-14 as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 I, Robert Chmiel, certify that: 1. I have reviewed this annual report on Form 10-KSB/A of National Coal Corp.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the small business issuer as of, and for, the periods presented in this report; 4. The small business issuer's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the small business issuer and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the small business issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b) Evaluated the effectiveness of the small business issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and c) Disclosed in this report any change in the small business issuer's internal control over financial reporting that occurred during the small business issuer's most recent fiscal quarter (the small business issuer's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the small business issuer's internal control over financial reporting; and 5. The small business issuer's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the small business issuer's auditors and the audit committee of the small business issuer's board of directors (or persons performing the equivalent function): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the small business issuer's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the small business issuer's internal control over financial reporting. Date: December 15, 2004 /s/ Robert Chmiel ------------------------- Robert Chmiel Chief Financial Officer EX-32 5 ex32-1g.txt EX-32.1 EXHIBIT 32.1 CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 (SUBSECTIONS (a) AND (b) OF SECTION 1350, CHAPTER 63 OF TITLE 18, UNITED STATES CODE) Pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350, chapter 63 of Title 18, United States Code), each of the undersigned officers of National Coal Corporation a Florida corporation (the "Company"), does hereby certify with respect to the Annual Report of the Company on Form 10-KSB/A for the eleven month period ended Inception (January 30, 2003) to December 31, 2003, as filed with the Securities and Exchange Commission (the "10-KSB Report") that: (1) the Form 10-KSB/A Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) the information contained in the Form 10-KSB/A Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date: December 15, 2004 /s/ Jon Nix ------------------------- Jon Nix President and Chief Executive Officer Date: December 15, 2004 /s/ Robert Chmiel -------------------------- Robert Chmiel, Chief Financial Officer -----END PRIVACY-ENHANCED MESSAGE-----