Item 1. Business.
Corporate Overview
We mine, process and sell high quality bituminous steam coal from mines located in East Tennessee and North Alabama and, until March 31, 2008, in Southeast Kentucky. We own the coal mineral rights to approximately 65,000 acres of land and lease the rights to approximately 17,700 additional acres excluding the Southeast Kentucky properties, known as Straight Creek, sold on March 31, 2008. As of December 31, 2008, our mining complexes included three active and two inactive underground mines, one underground mine in the development stage, one inactive and six active surface mines, and one highwall mine. In addition, we have two preparation plants and two unit train loading facilities in Tennessee served by the Norfolk Southern (“NS”) railroad. We are a minority joint venture partner in a barge loading facility on the Warrior River in North Alabama. We hold seven permits that allow us to open new or re-open existing mines close to our current operations. As of December 31, 2008, we controlled approximately 40.8 million estimated recoverable tons of coal reserves as defined by the SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted at the time of the reserve determination.
During the year ended December 31, 2008, we generated total revenues of $132.6 million and sold approximately 2.0 million tons of coal. Our revenues are derived primarily from the sale of coal to electric utility companies and industrial customers in the Southeastern United States pursuant to long-term contracts or open purchase order arrangements with long time customers. Long term contracts as customary in the industry are those with a duration of one year or more. Our largest customers were Georgia Power, Alabama Power, and Solutia, Inc., representing approximately 34%, 21% and 14% of our revenues, respectively.
In the year ended December 31, 2008, our mines produced approximately 1.8 million tons of coal. Approximately 21% of our production for 2008 was produced at underground mines and 79% was produced at our surface and highwall mining operations. During 2008, we successfully renegotiated several of our existing coal supply agreements resulting in an increased selling price per ton and additional revenues from those contracts. The weighted average selling price per ton is $75.28, $77.40, and $79.43 on 2.1 million, 1.0 million, and 0.35 million tons contracted for 2009, 2010, and 2011, respectively. We are consistently having negotiations with existing and new customers to obtain additional sales for coal produced from our controlled properties and permitted mines in Tennessee and Alabama.
One of our goals is to acquire and develop additional mining properties and increase production from our existing reserves as market conditions allow. We have not yet priced a portion of the coal we have the capability of producing over the next several years in order to take advantage of possible future market demand or to realize possible long term opportunities with certain users of the high quality coal contained in our reserve base. At December 31, 2008, our un-priced and uncommitted future production was approximately 0.2 million to 0.3 million tons in 2009, 1.1 million to 1.5 million tons in 2010, and 2.5 million tons in 2011.
Corporate History
Our business activity prior to April 30, 2003 reflected only the start-up of National Coal Corporation, a Tennessee corporation, which consisted of the formation of the corporation and the acquisition of certain properties referred to as the New River Tract. Prior to April 30, 2003, National Coal Corp., a Florida corporation, formerly known as Southern Group International, Inc., was a “blank check” company, which is a company that had no specific business plan or purpose or had indicated that its business plan was to engage in a merger or acquisition with an unidentified company or companies. On April 30, 2003, National Coal Corporation consummated a reorganization in which all of the outstanding shares of National Coal Corporation, a privately-held Tennessee corporation, were exchanged for 8,549,975 shares of Southern Group, Inc., which subsequently changed its name to National Coal Corp., a Florida corporation. National Coal Corporation was formed in January 2003, and from inception through June 30, 2003, National Coal Corporation was in the exploration stage with no operating revenue. We began mining in Tennessee in the third quarter of 2003 and were no longer in the exploration stage.
In April 2004, we acquired from U.S. Coal, Inc., mining permits, the Turley, Tennessee rail loadout facility, the Smoky Junction, Tennessee preparation plant, and mining equipment for an aggregate purchase price of $4.2 million plus the assumption of certain liabilities.
In October 2004, we acquired from Robert Clear Coal Corporation certain mining assets including mining permits and mining equipment for an aggregate purchase price of $5.5 million plus the assumption of certain liabilities and the obligation to replace $3.9 million of the seller’s reclamation bonds.
We acquired Kentucky operations known as Straight Creek and Pine Mountain, from Appalachian Fuels, LLC in November 2004. The assets were acquired for $12.5 million plus the assumption of certain liabilities and the obligation to replace $6.5 million of the seller’s reclamation bonds and included mining permits, a preparation plant, a rail load-out facility and mining equipment. This acquisition included two mining areas in Kentucky, each geographically separated and having access to a preparation plant and loading facility. We subsequently sold the Pine Mountain real property and mineral leases for $2.0 million and sold an option to acquire the remaining Pine Mountain properties consisting of a preparation plant for $1.0 million. We did not operate any coal mines on the Pine Mountain tracts during the time we controlled the properties. We sold the Straight Creek operations on March 31, 2008 for $11 million in cash and the release of approximately $7.0 in restricted cash used for reclamation bonds, $3.6 million in reclamation liabilities and $2.6 million of equipment related debt.
We acquired the Baldwin preparation plant and rail load-out facility located in Devonia, Tennessee in 2005 from Lexington Coal in return for the assumption of certain reclamation liabilities and subsequently spent $7.0 million during 2006 to refurbish and modernize the facility. The Baldwin facilities became fully operational in the third quarter of 2008.
In February 2006, we purchased a 42-mile short line railroad for approximately $2.0 million from Norfork-Southern which provides controlled access to our owned reserves on the New River tract to the Norfolk-Southern main line rail facilities at Oneida, Tennessee. We spent an additional $0.5 million to refurbish the line and make it operational. We engaged a third party contractor to maintain and operate our short line railroad which became fully operational in the third quarter of 2008.
We acquired our Alabama operations on October 19, 2007 through the acquisition of 100% of the common stock of Mann Steel Products, Inc. (Mann Steel), and changed its name to National Coal of Alabama. We have four mining areas in Alabama, defined by geographic location of mineral and surface leases. These properties are mined utilizing various surface mining methods that includes the removal of surface overburden with earth moving equipment such as excavators, loaders and a dragline. Coal mined on these properties is transported to customers via truck, third party rail loadout or barge.
In 2008 we acquired a 1,000 acre mineral and surface tract in eastern Tennessee that includes approximately 2.3 million tons of high quality coal. The purchase price was $7.0 million of which $2.0 million was paid in cash and $5.0 million in the issuance of 756,430 shares of our common stock. We also acquired a 524 acre mineral lease in eastern Tennessee that includes approximately 1.4 million tons of recoverable high quality coal for $.5 million.
We have not yet turned a profit and are highly leveraged. Additionally, our senior secured debt issued and outstanding at both National Coal Corp. and National Coal of Alabama restricts our ability to transfer funds between the two entities.
Mining Operations
As of December 31, 2008, we were operating four surface mines in Alabama, and three underground mines, two surface mines and one highwall mining operation in Tennessee. We operated mines in Kentucky until the sale of those operations on March 31, 2008.
Tennessee Properties
We have two mining areas in Tennessee defined by their proximity to our preparation plant facilities and rail loading facilities:
Baldwin Facility. The Baldwin preparation plant and rail loading facilities reside on the Southern portion of the New River Tract, a 65,000 acre parcel of owned mineral rights in Scott, Anderson and Campbell counties. This facility was refurbished at a cost of $7.0 million during 2006 for the purpose of providing coal processing and railroad loading operations to support our underground and surface mining activities from the New River Tract. The Baldwin facilities include the 750 ton per hour preparation plant and rail loadout and the short line railroad, which became fully operational were brought back into operation during the third quarter of 2008.
Smoky Junction and Turley Facilities. The Smoky Junction preparation plant and the Turley rail loading facility reside on the northern portion of the New River Tract. In addition to mines in the northern portion of the New River Tract, controlled properties that utilize the Turley and Smoky Junction facilities include Ketchen and TVA leased properties. The Ketchen property consists of approximately 7,000 acres of leased surface mining reserves and the TVA property consists of approximately 4,400 acres of leased underground reserves. In addition, the two tracts totaling approximately 1,500 acres and 4.0 million tons that we acquired in 2008 for $7.5 million are located in close proximity of the Smoky Junction preparation plant and the Turley rail loadout. The Smoky Junction preparation plant is a 250 ton per hour facility that allows us to process coal from various mining operations in this area of the New River Tract and from our leased TVA and Ketchen properties. The Turley loadout is a Norfork-Southern rail siding that provides us the capability to load raw or processed coal from mines from the New River, TVA or Ketchen tracts.
Kentucky Properties
We acquired our Kentucky operations on the Straight Creek and Pine Mountain tracts from Appalachian Fuels, LLC in November 2004. We had two mining areas in Kentucky, each geographically separated and each having access to a preparation plant and loading facility:
Straight Creek. During 2007 and 2008, all of our mining in Kentucky occurred on this tract of leased and owned mineral rights in Harlan, Bell and Leslie counties. All coal was processed at the Brittain preparation plant which has an estimated annual processing capacity of 1.8 million tons per year. All coal was loaded onto trains at the Viall rail loading facility which is located on the CSX railroad. We sold the Straight Creek operation on March 31, 2008 for $11 million in cash and the release of $3.6 million in reclamation liabilities and $2.7 million of equipment related debt.
Pine Mountain. On November 13, 2007, we received $2.0 million from the sale of real property and mineral leases at Pine Mountain, an idle mining complex and an additional $1.0 million from the sale to the same purchaser of an option entitling them to purchase for $10.00 our remaining properties which included the preparation plant. We did not mine the Pine Mountain tracts during the time that we controlled the property.
Alabama Properties
We have four active mining areas in Alabama, defined by geographic location of mineral and surface leases. The mining properties are located in Marion, Winston, Walker, Fayette, and Tuscaloosa counties. All or our mining complexes have access to customers via truck, third party rail or barge loading facilities.
L. Massey. The L. Massey surface mine produced 350,927 tons during 2008. L. Massey presently utilizes truck, shovel and dozer mining techniques. Our dragline was being used on this job when it experienced a major component failure during the first quarter of 2008. It was then moved to the Poplar Springs mine where the repairs were completed. All coal is loaded onto trucks operated by independent contractors and transported directly to the customer, to third-party rail loadouts or to a barge loadout, which is operated by Powhatan Dock, LLC, a 49% owned investment of National Coal of Alabama.
Poplar Springs. The Poplar Springs facilities include two surface mines that produced 354,752 tons during 2008. Poplar Springs utilized an excavator, bulldozers and wheel-loaders to extract coal until the dragline was moved to this mine in the third quarter of 2008. All coal is loaded onto trucks operated by independent contractors and transported directly to customers, to third-party rail loadouts or to the Powhatan barge loadout.
Crescent Valley. The Crescent Valley surface mine began production in July 2008 and produced 111,375 tons during 2008. Crescent Valley utilizes an excavator, bulldozers and wheel-loaders to extract coal. All coal is loaded onto trucks operated by independent contractors and transported directly to customers, to third-party rail loadouts or to the Powhatan barge loadout.
Davis Creek. The Davis Creek surface mine began production in September 2008 and produced 23,114 tons during 2008. Davis Creek utilizes an excavator, bulldozers and wheel-loaders to extract coal. All coal is loaded onto trucks operated by independent contractors and transported directly to customers, to third-party rail loadouts or to the Powhatan barge loadout.
Hickory Grove. The Hickory Grove surface mine produced 20,435 tons during 2008. Hickory Grove utilized an excavator, bulldozers and wheel-loaders to extract coal. All coal was loaded onto trucks operated by independent contractors and transported directly to customers, to third-party rail loadouts or to the Powhatan barge loadout. All planned mining activity was completed on the active permits and this mine was closed and reclaimed in February 2008.
Permitted Non-Operating Mines
Currently, we have four issued mining permits for new mines that are not yet operating and three issued permits for mines which were operating but have been idled, all of which are in Tennessee. We have also applied for permits, or have permit applications in various stages of processing, that should enable us to open two additional mines, one in Alabama and one in Tennessee, when issued.
The following table provides permitted reserves by mine location as of December 31, 2008 and the associated production for the years ending December 31, 2008, 2007 and 2006.
UG - Underground Mine, HWM - Highwall Miner
* Date opened shown. Alabama mines were acquired October 19, 2007. Production for 2007 is for the period October 20, 2007 to December 31, 2007.
** Mine #5 is an underground mine in the development stage as of December 31, 2008. Production has since begun in March 2009.
Transportation
Our Tennessee mining operations are within close proximity to our rail loadouts and major interstate highways, which give us flexibility for transporting our coal via truck or rail. In addition, our Turley rail load-out and our Baldwin preparation plant and loading facility are served by Norfork Southern. The Baldwin facility is served via a 42 mile short line railroad which we purchased in February 2006 from Norfolk-Southern Railroad. We began operating our short line railroad utilizing an independent, experienced short line rail operator during the third quarter of 2008. The short line railroad operates from our Baldwin facility and transports coal to the Norfolk-Southern main line in Oneida, Tennessee. The loaded trains are then transferred to the control of Norfolk-Southern and then on to the customers.
All of our Alabama operations are also within close proximity to major interstate highways, which provide access for trucking of our coal to our customers, to third-party rail loadouts, or to the Powhatan barge loadout facility. Powhatan started operations in December 2007 and we began shipping coal through that facility in January 2008.
In Tennessee and Alabama we utilize independent contractors to transport coal from the mine sites to preparation plants, load-out facilities, barge loading facilities and customers.
Marketing and Sales
Our marketing and sales efforts are performed by employees, consultants and independent coal brokers. Our sales efforts primarily are focused on increasing our customer base of electric utilities and various industrial concerns in the Southeastern region of the United States.
During the year ended December 31, 2008, we sold 2.0 million tons of coal at an average price of $65.00 per ton, resulting in approximately $129.4 million in coal sales. Our top three customers represented approximately 64% of the volume relating to these coal sales.
Customers
During the twelve months ended December 31, 2008, we generated all of our coal sales revenue from twenty-seven customers, six of which were electric utilities (64%), twenty of which were industrial companies (34%) and one was a coal reseller (2%). Most of our coal sales are derived from contracts of twelve months or longer and open purchase order arrangements with long standing customers. Some of our contracts contain price-reopeners and fuel surcharge provisions which allow adjustments to the price we receive for our coal when certain market conditions are met. We intend to expand the number of customers we serve as our coal production increases and enter into long term contracts for our coal production when pricing is favorable. The following table summarizes, as of December 31, 2008, the tons of coal that we are committed to deliver during the calendar years 2009 through 2011 from our Tennessee and Alabama operations at prices determined under existing contracts and open purchase order arrangements:
Employees
At December 31, 2008, we had 464 full-time employees, of which 398 were engaged in direct mining or processing operations, 18 in mining supervision, 20 in other operating capacities, and 28 in executive management, accounting and general administration. None of our employees are covered by a collective bargaining agreement. We consider our relationship with our employees to be favorable. We utilize the services of independent consultants as needed. The operating employees and supervisors are based in East Tennessee, and North Alabama. The Chief Executive Officer, Chief Operating Officer and Chief Financial Officer are based in Knoxville, Tennessee.
Business Strategy
Focus on safety and environmental stewardship. We are committed to establishing a reputation as the operator of the safest and most environmentally responsible mines in the country. Success at minimizing lost-time injuries will improve our cost structure, foster strong governmental and community relationships, and enhance our financial performance. We believe that environmental regulations will continue to become more restrictive, and that our commitment to environmental excellence will enhance our ability to comply with those regulations.
Increase production and develop reserves. We plan to expand coal production as market conditions allow. We hold permits allowing us to open four new mines and reopen three mines which have been idled on our properties. We also have applied for permits to open two additional mines, one in Alabama and one in Tennessee. At December 31, 2008, we controlled an estimated 40.8 million recoverable tons of coal, and we believe that we have substantial unproven coal reserves which may be developed after additional exploration work is completed.
Improve production efficiencies. We plan to continue to improve our operating efficiencies through greater economies of scale and capital improvements. As we expand our production capabilities, we plan to leverage further our fixed cost infrastructure and reduce our per ton production costs. In order to achieve new efficiencies, we spent approximately $7.0 million in 2006 to modernize our Baldwin preparation plant and rail load-out facility, which will enable us to reduce cost and expand processing capacity in the southern portion of our Tennessee reserves. In February 2006, we purchased a forty-two mile railroad line that enables us to transport coal from the Baldwin facility to the Norfolk Southern mainline at Oneida, TN. The railroad began operating during the third quarter of 2008 and further reduces our internal transportation costs from this area.
Continue to develop strong customer relationships. Since we commenced operations in July 2003, we have worked hard to develop a reputation for reliability, consistent quality and customer service. We intend to continue to develop strong relationships with our existing customers and new customers in order to enhance our market position and secure favorable long-term contracts. Currently, a significant portion of our 2009 planned production has been committed, primarily to existing customers.
Continue to acquire contiguous reserves. Our mining properties in Tennessee are located in close proximity to one another and are well served by adjacent railroad and interstate highway access. We believe that opportunities may exist to acquire nearby reserves to further leverage our railroad access and preparation plant facilities. Our Alabama mining properties are located approximately 300 miles from our corporate headquarters in Knoxville, Tennessee, and are well served by highway, railroad or barge access. Significant additional mineral leasing activity was on-going at the time we acquired our Alabama mining operations, which we intend to complete. Furthermore, we believe that opportunities still exist to secure additional reserves in close proximity to our existing reserves.
Competition
The coal industry is intensely competitive. We compete with numerous domestic coal producers and coal importers. We also compete with producers of other fuels used in electricity generation, including nuclear, and natural gas. In addition to competition from other fuels, major determinants of the price for which our coal can be sold include coal quality, the marginal cost of producing coal in other regions of the country, and transportation costs.
Coal Mining
Coal mining operations can be divided into surface and underground mining methods. The most appropriate mining method is determined by coal seam characteristics including geology, 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 method. For underground mining there are two primary methods - room and pillar and longwall; for surface mining there are three primary methods - truck-and-shovel mining, dragline mining, and highwall mining - the newest technique. We operate both surface and underground mining operations and utilize truck-and-shovel, dragline, highwall and room and pillar mining methods.
Surface mining. This method is used to extract coal deposits found closer to the surface and involves the removal of earth and rock covering the coal with various earth moving equipment. Typically, coal-mining operations will begin at the part of the coal seam that is closest to the surface and most economical to mine. As the seam is mined, it typically becomes more difficult and expensive to mine because the seam may become thinner or protrude more deeply into the earth, requiring removal of more material over the seam, known as “overburden.” As the amount of overburden increases, the cost to mine coal also increases. Many seams of coal in Central Appalachia are between one to ten feet thick and may be located hundreds of feet below the surface.
Surface mining uses draglines, large power shovels, or front-end loaders (“loaders”) to remove the earth or overburden that covers the coal. The overburden is moved to a previously mined area, either by the dragline or by large off-road trucks, to facilitate the reclamation process. The coal is then loaded into trucks for transport to a preparation plant, rail load-out facility, our port facility, or customers. Productivity depends on size of equipment, geological composition, and the ratio of overburden to coal.
Highwall mining. Highwall mining is a mining method in which a continuous mining machine is driven by remote control into the coal seam exposed by previous surface mining operations, which created a vertical wall on the face of the exposed topography. A continuous haulage system then carries the coal from the coal face to the surface for stockpiling and transport. This process forms a series of parallel, unsupported cuts along the highwall. It is vital that the remaining coal pillars between adjacent entries are capable of supporting the overburden structure.
Underground mining. Those seams that are too deep to surface mine may be economically mined with specialized equipment matched to the thickness of the coal seam. Underground mining methods consist of “room and pillar” and “longwall mining.” Room and pillar mining typically requires using a continuous miner to cut a system of entries into the coal, leaving pillars to support the strata above the coal. Shuttle cars then transport the coal from the digging face to a conveyor belt for transport to the surface. This method is often used to mine thin coal seams, and where geological conditions are not amenable to longwall mining. Coal recovery is typically 50% or less. All of our underground mining operations only utilize room and pillar with continuous mining methods.
Coal Characteristics
Heat value. The heat value of coal is commonly measured in Btu per pound of coal. Coal found in the Eastern and mid-Western regions of the United States, including Central and Southern Appalachia, tends to have a heat content ranging from 10,000 to 15,000 Btu per pound. The effect of moisture in coal, as sold, is included in references to Btu per pound of coal, unless otherwise indicated.
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 using this term, we refer to coal with sulfur content of 1.5% or less by weight. Compliance coal refers to coal, which, when consumed in the production of energy, produces less than 1.2 pounds of sulfur dioxide per million Btu. The strict emissions standards of the Clean Air Act have increased demand for lower sulfur coals. We expect continued high demand for lower sulfur coals 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).
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 for electric generating plants as it affects combustion performance and utilities 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 with less combustion efficiency. Moisture content in coal, as sold, can range from approximately 5% to 30% of the coal’s weight. Generally, the moisture content of coal from Central Appalachia ranges from 5% to 9%.
The other major market for coal is the steel industry. The type of coal used in steel making is referred to as metallurgical coal and is distinguished by special quality characteristics that include high carbon content, low expansion pressure and various other chemical attributes. Metallurgical coal is also high in heat content (as measured in Btu), and therefore is desirable to utilities as fuel for electricity generation. Consequently, metallurgical coal producers have the ongoing opportunity to select the market that provides maximum revenue. The price offered by steel makers for the metallurgical quality attributes is typically higher than the price offered by utility coal buyers that value only the heat content.
Once raw coal is mined, it is often crushed, sized and washed in preparation plants where 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.
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. Most of the coking coal comes from coal found in Northern and Central Appalachia.
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 utilities purchase coal on the basis of its total delivered cost per million Btu. The higher the Btu of the coal, the fewer tons the utility needs to buy to meet its requirements.
Price at the mine. The price of coal at the mine is influenced by its cost of production, geological characteristics - such as seam thickness, overburden ratios and depth of underground reserves and prices received for similar quality coal sold by our competitors. Eastern United States 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 costs than surface mining because it requires more people, greater development costs, and higher costs to remove impurities.
In addition to direct mining costs, the price of coal at the mine is also a function of quality characteristics such as heat value, sulfur, ash and moisture content. Metallurgical coal has higher carbon and lower ash content and is usually priced higher than steam coal produced in the same regions. Higher prices are paid for metallurgical coals with low volatility characteristics. Very few coal seams possess these unique metallurgical coal qualities.
Transportation costs. Coal used for domestic consumption is generally sold freight on board, or FOB, at the mine and shipped by railroad, truck, or barge. The buyer normally bears the cost of transportation from the loadout to its final destination. Export coal, however, is usually sold at the loading port, and coal producers are responsible for arranging and paying for shipment to the export coal-loading facility. The buyer does not acquire ownership of the coal or pay for it until it is loaded onto the ship.
Most electric utilities arrange long-term shipping contracts with rail, truck, or barge companies to assure stable delivered costs. Transportation can be a large component of a buyer’s cost, especially if long distances are involved such as from the Western areas of the US to the Southeast. Although the buyer pays the freight, transportation costs are still important to coal mining companies because buyers typically make their purchase decisions based on the delivered cost per Btu, and transportation costs may add to or detract from a specific mine’s price position. According to the National Mining Association, railroads account for nearly two-thirds of total coal shipments in the United States. Trucks and overland conveyors haul coal over shorter distances, while lake carriers and ocean vessels move coal mainly 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. Coal mines in Central and Southern Appalachia generally are served by either the Norfolk-Southern or the CSX rail lines.
Regulatory Matters
Federal, state and local authorities regulate the United States 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, the discharge of materials into the environment, surface subsidence from underground mining, and the effects of mining on groundwater quality and availability. The Mine Safety and Health Administration, or MSHA, is the U.S. Department of Labor agency responsible for the health and safety of miners. The Office of Surface Mining, or OSM, is the Department of the Interior agency which governs the issuance of permits and is responsible for overseeing the reclamation, restoration and other environmental processes for the coal mining industry.
The industry is also 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. We believe that we have obtained all permits currently required to conduct our present mining operations and are in compliance with all MSHA and OSM regulations pursuant to our operations. We may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that a proposed development for, or production of, coal may have on the environment. These requirements could prove costly and time-consuming, and could delay commencing or continuing development or impact producing operations. Future legislation and administrative regulations may emphasize the protection of the environment and, as a consequence, our 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 and delays, interruptions or a termination of operations, the extent of which cannot be predicted.
Two bills have been introduced in the Tennessee Legislature that could have an adverse effect on our ability to mine coal profitability in Tennessee. One of the bills proposes a significant increase in the severance tax payable to the State from $0.20 per ton to $1.00 per ton. The second bill proposes to prohibit any coal mining that would alter or disturb any ridge line above two thousand (2,000) feet in elevation. A number of our seams of coal in the state of Tennessee are above two thousand (2,000) feet in elevation. Accordingly, if the Bill were to pass the Legislature, our ability to economically recover coal from those seems may be negatively affected.
We endeavor to conduct our 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. The majority of any such violations result from natural causes, such as heavy rainfall, diverse temperature conditions, or unknown geological conditions that cause physical changes to the land surface or water levels resulting in excess sedimentation in streams or land slides. None of the violations to date or the monetary penalties assessed upon us 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 states, including the states in which we operate, have 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 United States industry. While regulation has a significant effect on our operating costs, our regional competitors are subject to the same degree of regulation.
Environmental Laws
We are subject to various federal and state environmental laws. Some of these laws, discussed below, place many requirements on our coal mining operations. Federal and state regulations require regular monitoring of our 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 OSM, establishes mining, environmental protection and reclamation standards for all aspects of surface mining as well as many aspects of underground 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 as in Kentucky, the state becomes the regulatory authority.
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.
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 expired on September 30, 2004, is $0.35 per ton on surface-mined coal and $0.15 per ton on deep-mined coal. As of October 1, 2007, the fee dropped to $0.315 per ton on surface-mined coal and $0.135 per ton on underground-mined coal. Since September 30, 2004, a fee is assessed each year to cover the expected health care benefit costs of the orphan beneficiaries.
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 and State regulatory
agencies are involved in monitoring or permitting specific aspects of mining operations. The United States 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 United States Army Corps of Engineers (“COE”) regulates activities affecting navigable waters and the United States Bureau of Alcohol, Tobacco and Firearms (“ATF”) regulates the use of explosives in blasting.
We do not believe there are any substantial matters that pose a risk to maintaining our existing mining permits or hinder our ability to acquire future mining permits. It is our 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 coal industry has witnessed a shift in demand to low sulfur coal production driven by regulatory restrictions on sulfur dioxide emissions from coal-fired power plants. 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 ten 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.
For example, in 1995, Phase I of the Clean Air Act Acid Rain program required high sulfur coal plants to reduce their emissions of sulfur dioxide to 2.5 pounds or less per million Btu, and in 2000, Phase II of the Clean Air Act tightened these sulfur dioxide restrictions further to 1.2 pounds of sulfur dioxide per million Btu. Currently, electric power generators operating coal-fired plants can comply with these requirements by:
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burning compliance coal, either exclusively or mixed with higher sulfur coal;
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installing pollution control devices such as scrubbers, which reduce the sulfur emissions from burning coal;
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reducing electricity generating levels; or
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purchasing or trading emission credits to allow them to comply with the sulfur dioxide emission compliance requirements.
However, as new and proposed laws and regulations, including the Clean Air Interstate Rule and the Clean Air Mercury Rule, require further reductions in emissions, coal-fired utilities may need to install additional pollution control equipment, such as wet scrubbers, to comply. Installation of such additional pollution control equipment could potentially result in a decrease in the demand for low sulfur coal (because sulfur would be removed by the new equipment), potentially driving down prices for low sulfur coal.
Clean Water Act
The Clean Water Act of 1972 affects coal mining operations by establishing water quality standards and regulating alteration of surface water bodies. Much of the responsibility for standard setting, monitoring, and enforcement is delegated to state agencies, with federal oversight. There are three major aspects in the standard-setting process. First, the states establish use designations for all surface water bodies. Second, scientifically-based water quality criteria (numeric or narrative) are established to be protective of the designated uses. These criteria include total maximum daily load (“TMDL”) discharge standards which are monitored and enforced through the National Pollution Discharge Elimination System (“NPDES”). Water discharges from each mine operation are regulated within the NPDES process. The third component is the anti-degradation standard, which establishes characteristics of “high quality
streams”, and prohibits their degradation. Standards for discharging water from mine sites to high quality streams are very stringent. Upgrading stream designations to “high quality” in the areas in which coal mine operations are located can potentially result in increased water treatment costs that can increase both permitting costs and coal production costs.
Resource Conservation and Recovery Act
The Resource Conservation and Recovery Act, which was enacted in 1976, affects coal mining operations by establishing requirements for the treatment, storage and disposal of hazardous waste. Coal mine waste, such as overburden and coal cleaning waste, 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 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, which became binding on all countries that had ratified the Kyoto Protocol in February 2005, as a result of Russia’s ratification in November 2004. 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 did not ratify 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 during 2004, coal accounted for 34% of the total. Efforts to control greenhouse gas emissions could result in reduced use of coal if electricity generators switch to lower carbon sources of fuel.
Regulation of greenhouse gases in the United States may happen as a result of the recent change in administration at the Federal level. Much discussion has taken place, along with proposed legislative initiatives, at both the State and Federal levels that would regulate greenhouse emissions. Any significant change in regulation may require additional controls on coal-fueled power plants and industrial boilers which could lead to switching to lower carbon fuels. Ultimately, such regulations could lead to a reduction in demand for coal.
Permitting
Mining companies must obtain numerous permits from both Federal and State regulatory agencies that impose strict environmental and safety regulations and oversight on their operations. 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.
We must obtain permits from applicable state regulatory authorities before we begin 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, we collect geologic data to define and model the soil and rock structures and coal that will be mined. We develop mine and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. The mine and reclamation plans incorporate the provisions of SMCRA, 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 along with 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 prior to approval. SMCRA mine permits can take over a year to prepare, depending on the size and complexity of the mine, and often take six months to three years for approval. Regulatory authorities have considerable discretion in the timing of permit issuance and the public has the right to comment on and otherwise engage in the permitting process, including through intervention in the courts.
We do not believe there are any substantial matters that pose a risk to maintaining our existing mining permits or hinder our ability to acquire future mining other than possible legislative matters that may be enacted by various state and federal agencies. It is our policy to ensure that our operations are in full compliance with the requirements of the SMCRA and state laws and regulations governing mine reclamation
Glossary of Terms
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.
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).
Coal Seam. Coal deposits occur in layers. Each layer is called a “seam.”
Compliance Coal. Coal having a sulfur dioxide content of 1.2 pounds or less per million Btu when consumed in the production of energy, as required by Phase II of the Clean Air Act.
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 which transport it to the surface for processing.
Fossil Fuel. Fuel such as coal, petroleum or natural gas formed from the fossil remains of organic material.
Overburden. The layers of earth and rock covering a coal seam. In surface mining operations, overburden is removed prior to coal extraction.
Reclamation. A process of restoring land and the environment to an approved state following mining activities. The process commonly includes “re-contouring” 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.
Reserves. That part of a mineral deposit that can be economically and legally extracted or produced at the time of the reserve determination.
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 created where the coal was mined; pillars are areas of coal left between the rooms to support overlying strata and surface structures.
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. 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 1.5% or less sulfur.
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.
Available Information
We make available our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, along with any related amendments and supplements on our website as soon as reasonable practicable after we electronically file or furnish such materials with or to the Securities and Exchange Commission, or the SEC. These reports are available, free of charge, at www.nationalcoal.com. Our website and the information contained in it do not constitute part of this annual report or any other report we file with, or furnish, to the SEC.
Item 1A.
Item 1A. Risk Factors.
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.
Risks Related To Our Business
Our substantial level of indebtedness could adversely affect our financial condition.
We have, and will continue to have substantial indebtedness. At December 31, 2008, we had approximately $102 million principal value of total senior debt. Our high level of indebtedness could have important consequences, including the following:
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reducing our ability to obtain additional financing;
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reducing our cash flow;
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placing us at a competitive disadvantage compared to our competitors that may have proportionately less debt or greater financial resources;
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hindering our flexibility in dealing with changes in our business and the industry; and
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making us more vulnerable to economic downturns and adverse developments.
Despite existing debt levels, we may still be able to incur substantially more debt, which would increase the risks associated with our leverage.
We may be able to incur substantial amounts of additional debt in the future. Although the terms of our existing credit facilities may limit our ability to incur additional debt, such terms do not and will not prohibit us from incurring substantial amounts of additional debt for specific purposes or under certain circumstances. The incurrence of additional debt could adversely impact our ability to service payments on senior debt.
We may not be able to generate the amount of cash needed to pay interest and principal amounts on our debt. We are limited in our ability to use cash generated at National Coal of Alabama, our subsidiary acquired in 2007, in our other operations.
We rely primarily on our ability to generate cash flows from operations to service our debt. If we do not generate sufficient cash flows to meet our debt service and working capital requirements, we may need to seek additional financing. If we are unable to obtain financing, we could be forced to sell our assets or those of our subsidiaries under unfavorable circumstances to make up for any shortfall in our payment obligations. Our existing credit facilities limit our ability to sell assets and also restrict the use of the proceeds from any such sale. Therefore, even if forced to do so, we may not be able to sell assets quickly enough or for sufficient amounts to enable us to meet our debt obligations.
National Coal of Alabama, Inc. is restricted in its ability to distribute cash to our other consolidated companies for use in their operations under the terms of our 12% Notes due 2012. On an annual basis, National Coal of Alabama can distribute cash for use in our other operations only if it meets certain EBITDA-based operating requirements for the immediately preceding fiscal year. Additionally, our subsidiary, National Coal Corporation, has entered into a management services agreement with National Coal of Alabama, Inc. that compensates National Coal Corporation for services that it provides to National Coal of Alabama, and a tax sharing agreement that requires National Coal of Alabama to make payments to us in respect of its tax liability. During 2008, National Coal of Alabama’s operations to provided limited cash for use in our other operations and we do not anticipate any significant contributions of cash by National Coal of Alabama during 2009. As a result of these provisions and agreements, there is no assurance that cash generated by National Coal of Alabama will be available for use in our other operations if those operations continue to experience negative cash flow.
We may be unable to comply with restrictions imposed by our credit facilities and other financing arrangements.
The agreements governing our outstanding senior debt impose a number of restrictions on us. For example, the terms of our credit facilities contain financial and other covenants that create limitations on our ability to effect acquisitions or dispositions, incur additional debt and may require us to maintain various financial ratios and comply with various other financial covenants. Our ability to comply with these restrictions may be affected by events beyond our control and, as a result, we may be unable to comply with these restrictions. A failure to comply with these restrictions could adversely affect our ability to borrow under our credit facilities or result in an event of default under these agreements. In the event of a default, our lenders could terminate their commitments to us and declare all amounts borrowed, together with accrued interest and fees, immediately due and payable. If this were to occur, we might not be able to pay these amounts, or we might be forced to seek an amendment to our financing arrangements which could make the terms of these arrangements more onerous for us.
In the first, second and third quarters of 2007, we failed to meet certain financial covenants required under our term loan credit facility with Guggenheim Corporate Funding, LLC, which is now terminated. In each instance, waivers of covenant failures and modifications of loan terms in order to bring financial covenants better in line with capabilities were obtained, however, penalties were incurred including an increase in rates and $100,000 in fees, plus the need to refinance the loan in order to obtain relief from the continuing difficulty with financial covenants. In the refinancing transaction, we incurred $323,000 in legal costs plus a fee of approximately $1,112,000 paid through the issuance of a stock purchase warrant.
In the second, third and fourth quarters of 2008, National Coal of Alabama, Inc failed to meet certain financial covenants required under its 12% Notes due 2012. In each instance, waivers of covenant failures and modifications of future financial covenants were obtained. With respect to the second and fourth quarter waivers only, we were charged penalties of $300,000 each quarter for covenant waiver and modification.
Continuing unfavorable economic conditions could have a material adverse effect on our results of operations
Economic conditions in the United States and throughout much of the world have undergone a sudden, sharp economic downturn. The recent distress in the financial market has resulted in extreme volatility and declines in security prices and diminished liquidity and credit availability. There can be no assurance that our liquidity and our ability to access the credit or capital markets will not continue to be affected by changes in the financial markets and the global economy. Continuing turmoil in the financial markets could make it more difficult for us to access capital, sell assets, refinance our existing indebtedness, attain waivers for covenant violations from our lenders if necessary, attain future bonding capacity required to expand our operations, enter into agreements for new indebtedness, or obtain funding through the issuance of our securities.
We face numerous uncertainties in estimating our economically recoverable coal reserves, and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs or decreased profitability.
We estimate that as of December 31, 2008, we control approximately 40.8 million tons of proven and probable reserves that are recoverable at this time. We base our reserve estimates on engineering, economic and geological data assembled and analyzed by our staff and independent mining engineering firm. Our estimates of our proven and probable reserves and our recoverable reserves, as well as the Btu or sulfur content of our reserves are revised and updated periodically to reflect the resolution of uncertainties and assumptions, the production of coal from the reserves and new drilling or other data received.
There are numerous uncertainties inherent in estimating quantities and qualities of and costs to mine recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves and net cash flows necessarily depend upon a number of variable factors and assumptions, all of which may vary considerably from actual results such as:
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geological and mining conditions which may not be fully identified by available exploration data or which may differ from experience in current operations;
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historical production from the area compared with production from other similar producing areas;
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the assumed effects of regulation and taxes by governmental agencies; and
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assumptions concerning coal prices, operating costs, mining technology improvements, severance and excise tax, development costs and reclamation costs.
For these reasons, estimates of the economically recoverable quantities and qualities attributable to any particular group of properties, classifications of reserves based on risk of recovery and estimates of net cash flows expected from particular reserves prepared by different engineers or by the same engineers at different times may vary substantially. Actual coal tonnage recovered from identified reserve areas or properties and revenues and expenditures with respect to our reserves may vary materially from estimates. As a result, the reserve estimates set forth in this report may differ materially from our actual reserves. Inaccuracies in our estimates related to our reserves could result in lower than expected revenues, higher than expected costs, or decreased profitability.
Our future success depends upon our ability to continue acquiring and developing coal reserves that are economically recoverable and to raise the capital necessary to fund our expansion.
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 efficiently 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. In addition, we must also generate enough capital, either through our operations or through outside financing, to mine these additional reserves. Our current strategy includes increasing our coal reserves through acquisitions of other mineral rights, leases, or producing properties and continuing to use our existing properties. Our ability to further expand our operations may be dependent on our ability to obtain sufficient working capital, either through cash flows generated from operations, or financing activities, or both. Mining coal in Central and Southern Appalachia can present special difficulties. Characteristics of the land and the permitting process may adversely affect our mining operations, our costs and the ability of our customers to use the coal that we mine. The geological characteristics of our coal reserves, such as depth of overburden and coal seam thickness, make them complex and costly to mine. As mines become depleted, replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. These factors could have a material adverse affect on our mining operations and costs, and our customers’ ability to use the coal we mine.
Our ability to implement our planned development and exploration projects is dependent on many factors, including the ability to receive various government permits.
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. For example, we may not be successful in acquiring contiguous properties that will leverage our existing facilities. In addition, in order to develop our coal deposits, we must receive various governmental permits. Before a mining permit is issued on a particular parcel, interested parties are eligible to file petitions to declare the land unsuitable for mining. For example, on November 10, 2005, two environmental groups filed a petition to halt the expansion of surface mining activities on the New River Tract and surrounding areas.
Although this petition was dismissed, management’s time and the Company’s resources were consumed in the process. We cannot predict whether we will continue to receive the permits necessary for us to expand our operations.
Defects in title or loss of any leasehold interests in our properties could adversely affect our ability to mine these properties.
We conduct, or plan to conduct, a significant part of our mining operations on properties that we lease. A title defect or the loss of any lease could adversely affect our ability to mine the associated reserves. Title to most of our owned or leased properties and mineral rights is not usually verified until we make a commitment to develop a property, which may not occur until after we have obtained necessary permits and completed exploration of the property. In some cases, we rely on title information or representations and warranties provided by our lessors or grantors. Our right to mine some of our reserves may be adversely affected if defects in title or boundaries exist or if a lease expires. Any challenge to our title could delay the exploration and development of the property and could ultimately result in the loss of some or all of our interest in the property and could increase our costs. In addition, if we mine on property that we do not own or lease, we could incur liability for such mining. Some leases have minimum production requirements or require us to commence mining in a specified term to retain the lease. Failure to meet those requirements could result in losses of prepaid royalties and, in some rare cases, could result in a loss of the lease itself.
Due to variability in coal prices, the length of our coal supply agreements, as well as certain provisions in our coal supply agreements, we may be unable to sell coal at a profit.
We typically sell our coal for a specified per ton amount and at a negotiated price pursuant to both short-term contracts and contracts of twelve months or greater. For the year ended December 31, 2008, 88% of the coal we produced was sold under contracts of twelve months or greater. Price adjustment, “price reopener” and other similar provisions in long-term supply agreements may reduce the protection from short-term coal price volatility traditionally provided by such contracts. Any adjustment or renegotiation leading to a significantly lower contract price would result in decreased revenues and lower our gross margins. Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or our customers during the duration of specified events beyond the control of the affected party. Most of our coal supply agreements contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, hardness and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or, in the extreme, termination of the contracts. Consequently, due to the risks mentioned above with respect to long-term supply agreements, we may not achieve the revenue or profit we expect to achieve from these sales commitments. In addition, we may not be able to successfully convert these sales commitments into long-term supply agreements.
We are subject to market risk with respect to a substantial portion of our coal production commencing in 2010.
We have not yet priced a substantial portion of the coal we have the capability of producing over the next several years in order to take advantage of possible future market demand or to realize possible long term opportunities with certain users of the high quality coal reserves we control. At December 31, 2008, our un-priced and uncommitted future production was approximately 0.2 million to 0.3 million tons in 2009, 1.1 million to 1.5 million tons in 2010, and 2.5 million tons in 2011, or approximately 11%, 56% and 88%, respectively, of our planned production for such periods. For the year ended December 31, 2008, 88% of the coal we produced was sold under contracts of twelve months or greater. Unless and until we enter into long-term contracts for our coal at fixed prices, the price at which we will sell our future production remains unknown. If coal prices drop or do not improve sufficiently prior to 2010, we may be forced to sell our coal at depressed prices, which would have a material adverse affect on our operations and profitability and there is no assurance that the Company will be able to refinance its senior debt due December 2010.
The coal industry is highly cyclical, which subjects us to fluctuations in prices for our coal.
We are exposed to swings in the demand for coal, which has an impact on the prices for our coal. The demand for coal products and, thus, the financial condition and results of operations of companies in the coal industry, including us, are generally affected by macroeconomic fluctuations in the world economy and the domestic and international demand for energy. Any material decrease in demand for coal could have a material adverse effect on our operations and profitability. In recent years, volatility in coal prices has become the norm rather than the exception.
We depend heavily on a small number of large customers, the loss of any of which would adversely affect our operating results.
For the year ended December 31, 2008, we derived approximately 69% of our coal revenues from sales to our three largest customers. At December 31, 2008, we had coal supply agreements with these customers that expire at various times through 2011. When these agreements expire, we may not be successful at renegotiating them and these customers may not continue to purchase coal from us pursuant to long-term coal supply agreements. If a number of these customers were to significantly reduce their purchases of coal from us or if we were unable to sell coal to them on terms as favorable to us as the terms under our current agreements, our financial condition and results of operations could suffer materially.
There is no assurance that we will find purchasers of our product at profitable prices.
If we are unable to achieve supply contracts, or are unable to find buyers willing to purchase our coal at profitable prices, our revenues and operating profits could suffer.
A substantial or extended decline in coal prices could reduce our revenues and the value of our coal reserves.
The prices we can charge for coal are influenced by factors beyond our control, including:
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the supply of, and demand for, domestic and foreign coal;
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the demand for electricity;
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the cost of transportation;
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the proximity to and capacity of transportation facilities;
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domestic and foreign governmental regulations and taxes;
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air emission standards for coal-fired power plants;
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regulatory, administrative and court decisions;
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the price and availability of alternative fuels, including the effects of technological developments; and
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the effect of worldwide energy conservation measures.
Our results of operations are dependent upon the prices we charge for our coal as well as our ability to improve productivity and control costs. Any adverse change in the supply to demand ratio would cause spot prices to decline and require us to increase productivity and lower costs in order to maintain our margins. If we are not able to maintain our margins, our operating results could be adversely affected. Therefore, price declines may adversely affect operating results for future periods and our ability to generate cash flows necessary to improve productivity and invest in 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. If deterioration of the creditworthiness of our customers or trading counterparties occurs, our business could be adversely affected.
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, a meaningful increase in coal prices could encourage the development of expanded capacity by new or existing coal producers. Any overcapacity could reduce coal prices in the future.
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, play a critical role in a customer’s purchasing decision. Increases in transportation costs could make our coal less competitive as a source of energy or could make some of our operations less competitive than other sources of coal.
Coal producers depend upon rail, barge, trucking, overland conveyor and other systems to deliver coal to their customers. 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.
The coal industry is intensely competitive, and our failure to compete effectively could reduce our revenue and margins, and delay or prevent our ability to service our debt.
We operate in a highly competitive industry with regional, national and international energy resources companies. We compete based primarily on price, and we believe that the principal factors that determine the price for which our coal can be sold are:
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competition from energy sources other than coal;
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coal quality;
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efficiency in extracting and transporting coal; and
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proximity to customers.
Some of our competitors have longer operating histories and substantially greater financial and other resources than we do. Our failure to compete effectively could reduce our revenues and margins, and delay or prevent our ability to make payments on our debt.
Significant competition from entities with greater resources could result in our failure.
We operate in a highly competitive industry with national and international energy resources companies. Some of our competitors have longer operating histories and substantially greater financial and other resources than we do. Our competitors’ use of their substantially greater resources could overwhelm our efforts to operate successfully and could cause our failure.
There is no assurance that our limited revenues will be sufficient to operate profitably, or that we will generate greater revenues in the future.
We were formed to create a regional coal producer with desires to expand as opportunities arose. We had no revenues from inception until the third quarter 2003 when we began mining operations. We are not profitable and have a limited operating history. We must be regarded as a risky venture with all of the unforeseen costs, expenses, problems, risks and difficulties to which such ventures are subject.
Our coal sales for the year ended December 31, 2008 were approximately $129.4 million. There is no assurance that we can continue to achieve sales at that level or generate profitable sales. We expect that many other coal producers could produce coal at lower costs per ton than our production cost per ton. If those companies price their coal based on their lower cost, it could adversely affect our revenues and profits, if any. There is no assurance that we will ever operate profitably. There is no assurance that we will generate continued revenues or any profits, or that the market price of our common stock will be increased thereby.
Our inability to diversify our operations may subject us to economic fluctuations within our industry.
Our limited financial resources reduce the likelihood that we will be able to diversify our operations. Our probable inability to diversify our activities into other coal mining areas will subject us to economic fluctuations within our market area and therefore increase the risks associated with our operations.
The loss of key management personnel could adversely affect our business.
We are heavily dependent upon the skills, talents, and abilities of our executive officers and board of directors to implement our business plan. Given the intense competition for qualified management personnel in our industry, the loss of the services of any key management personnel may significantly and detrimentally affect our business and prospects. We may not be able to retain some or all of our key management personnel, and even if replaceable, it may be time consuming and costly to recruit qualified replacement personnel.
We face risks inherent to mining which 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 other variations in geologic conditions. Any of these factors could increase the cost of operating our business, which would lower or eliminate our margins.
Increases in the price of steel, diesel fuel or rubber tires could negatively affect our operating costs.
Our coal mining operations use significant amounts of steel, diesel fuel and rubber tires. The costs of roof bolts we use in our underground mining operations depend on the price of scrap metal. We also use significant amounts of diesel fuel and tires for the trucks and other heavy machinery we use, particularly at our six active surface mining operations. If the prices of steel, diesel fuel and other commodity based products increase, our operating costs could be negatively affected.
A shortage of skilled labor in the mining industry could pose a risk to achieving optimal labor productivity and competitive costs, which could adversely affect our profitability.
Efficient coal mining using modern techniques and equipment requires experienced, skilled laborers with proficiency in multiple mining tasks. In order to support our ongoing labor needs and possible expansion opportunities, we have sponsored both in-house and vocational coal mining programs at the local level in order to train additional skilled laborers. In the event the shortage of experienced labor continues or worsens or we are unable to train the necessary amount of skilled laborers, there could be an adverse impact on our labor productivity and costs and our ability to maintain or expand production and therefore have a material adverse effect on our earnings.
Disruptions in the quantities of coal produced by our contract mine operators could impair our ability to fill customer orders or increase our operating costs. We may be unable to purchase sufficient quantities of coal from third parties to meet our contractual commitments or the price of such coal may be greater than we had expected.
We use independent contractors to mine coal at certain of our mining operations, including our operations in Tennessee. Operational difficulties at contractor-operated mines, changes in demand for contract miners from other coal producers, and other factors beyond our control could affect the availability, pricing, and quality of coal produced for us by contractors. Disruptions in the quantities of coal produced for us by our contract mine operators could impair our ability to fill our customer orders or require us to purchase coal from other sources in order to satisfy those orders. If we are unable to fill a customer order or if we are required to purchase coal from other sources in order to satisfy a customer order, we could lose existing customers and our operating costs could increase.
We may be unable to realize the benefits we expect to occur as a result of the acquisition of Mann Steel Products or other acquisitions that we may undertake.
We continually seek to expand our operations and coal reserves through acquisitions of other businesses and assets, including leasehold interests. On October 19, 2007, we acquired 100% of the common stock of Mann Steel Products, Inc. (now National Coal of Alabama, Inc.) for approximately $58.7 million in cash. Certain risks, including those listed below, could cause us not to realize the benefits we expect to occur as a result of this acquisition:
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uncertainties in assessing the value, risks, profitability and liabilities (including environmental liabilities) associated with certain businesses or assets;
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the potential loss of key customers, management and employees of an acquired business;
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the possibility that operating and financial synergies expected to result from an acquisition do not develop;
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problems arising from the integration of an acquired business; and
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unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying the rationale for the acquisition.
Risks Related to Environmental and Other Regulation
The government regulates 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.
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 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, which became binding on all countries that had ratified the Kyoto Protocol in February 2005, as a result of Russia’s ratification in November 2004. 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 did not ratify 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 during 2004, coal accounted for 34% of the total. Efforts to control greenhouse gas emissions could result in reduced use of coal if electricity generators switch to lower carbon sources of fuel.
Regulation of greenhouse gases in the United States may happen as a result of the recent change in administration at the Federal level. Much discussion has taken place, along with proposed legislative initiatives, at both the State and Federal levels that would regulate greenhouse emissions. Any significant change in regulation may require additional controls on coal-fueled power plants and industrial boilers which could lead to switching to lower carbon fuels. Ultimately, such regulations could lead to a reduction in the demand for coal.
Two bills have been introduced in the Tennessee Legislature that could have an adverse effect on our ability to mine coal profitability in Tennessee. One of the bills proposes to increase the severance tax payable to the State from $0.20 per ton to $1.00 per ton. The second bill proposes to prohibit any coal mining that would alter or disturb any ridge line above two thousand (2,000) feet in elevation. A number of our seams of coal in the State of Tennessee are above two thousand (2,000) feet in elevation. Accordingly, if the Bill were to pass the Legislature, our ability to economically recover coal from those seems may be negatively affected.
Our operations could be adversely affected if we fail to maintain required bonds.
Federal and state laws require surety 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. At December 31, 2008, we had approximately $16.7 million of cash invested in money market funds and certificates of deposit, against which irrevocable bank letters of credit or surety bonds are written in favor of OSM (Tennessee operations), the Kentucky Department of Natural Resources, or the Alabama Surface Mining Commission, and have posted a $0.7 million letter of credit secured by our executive office building in favor of OSM. Reclamation bonds are typically renewable on a yearly basis if they are not posted with cash. Our failure to maintain, or inability to acquire, 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:
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lack of availability, higher expense or unfavorable market terms of new bonds;
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restrictions on the availability of collateral for current and future third-party bond issuers under the terms of our existing credit facilities; and
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the exercise by third-party bond issuers of their right to refuse to renew the bonds.
Terrorist threats and environmental zealotry 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. Our business also may be affected by environmental activists who engage in activities intended to disrupt our business operations. In particular, environmental activists have conducted protests outside the homes of certain of our former executives, including our former Chief Executive Officer. We spent approximately $300,000, $400,000 and $900,000 during the years ended December 31, 2008, 2007 and 2006, respectively, on security measures. 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 failure to obtain and renew permits necessary for our mining operations could negatively affect our business.
Mining companies must obtain numerous permits that regulate environmental and health and safety matters in connection with coal mining, including permits issued by various federal and state agencies and regulatory bodies. We believe that we have obtained the necessary permits to mine our developed reserves at our mining complexes. However, as we commence mining our undeveloped reserves, we will need to apply for and obtain the required permits. The permitting rules are complex and change frequently, making our ability to comply with the applicable requirements more difficult or even impossible. In addition, private individuals and the public at large have certain rights to comment on and otherwise engage in the permitting process, including through intervention in the courts. Accordingly, the permits we need for our mining operations may not be issued, or, if issued, may not be issued in a timely fashion. The permits may also involve requirements that may be changed or interpreted in a manner which restricts our ability to conduct our mining operations or to do so profitably. An inability to conduct our mining operations pursuant to applicable permits would reduce our production, cash flow and profitability.
The characteristics of coal may make it difficult for coal users to comply with various environmental standards related to coal combustion or utilization. As a result, coal users may switch to other fuels, which could affect the volume of our sales and the price of our products.
Coal contains impurities, including but not limited to sulfur, mercury, chlorine, carbon and other elements or compounds, many of which are released into the air when coal is burned. Stricter environmental regulations of emissions from coal-fueled power plants could increase the costs of using coal thereby reducing demand for coal as a fuel source and the volume and price of our coal sales. Stricter regulations could make coal a less attractive fuel alternative in the planning and building of power plants in the future.
Proposed reductions in emissions of mercury, sulfur dioxides, nitrogen oxides, particulate matter or greenhouse gases may require the installation of costly emission control technology or the implementation of other measures, including trading of emission allowances and switching to other fuels. For example, in order to meet the federal Clean Air Act limits for sulfur dioxide emissions from power plants, coal users may need to install scrubbers, use sulfur dioxide emission allowances (some of which they may purchase), blend high sulfur coal with low-sulfur coal or switch to other fuels. Reductions in mercury emissions required by certain states will likely require some power plants to install new equipment, at substantial cost, or discourage the use of certain coals containing higher levels of mercury. Recent and new proposals calling for reductions in emissions of carbon dioxide and other greenhouse gases could significantly increase the cost of operating existing coal-fueled power plants and could inhibit construction of new coal-fueled power plants. Existing or proposed legislation focusing on emissions enacted by the United States or individual states could make coal a
less attractive fuel alternative for our customers and could impose a tax or fee on the producer of the coal. If our customers decrease the volume of coal they purchase from us or switch to alternative fuels as a result of existing or future environmental regulations aimed at reducing emissions, our operations and financial results could be adversely impacted.
If the assumptions underlying our estimates of reclamation and mine closure obligations are inaccurate, our costs could be greater than anticipated.
SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining, as well as most aspects of underground mining. We base our estimates of reclamation and mine closure liabilities on permit requirements and our engineering expertise related to these requirements. Our management and engineers periodically review these estimates. The estimates can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, which we refer to as Statement No. 143, requires us to record these obligations as liabilities at fair value. In estimating fair value, we consider the estimated current costs of reclamation and mine closure and applied inflation rates and a third-party profit, as required by Statement No. 143. The third-party profit is an estimate of the approximate markup that would be charged by contractors for work performed on our behalf. If actual costs differ from our estimates, our profitability could be negatively affected.
Our operations may have a negative impact on the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in material liabilities to us.
Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. We could become subject to claims for toxic torts, natural resource damages and other damages as well as for the investigation and clean up of soil, surface water, groundwater, and other media. Such claims may arise, for example, out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or even for the entire share.
We maintain coal refuse areas and slurry impoundments at our Tennessee mining complexes. Such areas and impoundments are subject to extensive regulation. Slurry impoundments have been known to fail, releasing large volumes of coal slurry into the surrounding environment. Structural failure of an impoundment can result in extensive damage to the environment and natural resources, such as bodies of water that the coal slurry reaches, as well as liability for related personal injuries and property damages, and injuries to wildlife. Some of our impoundments overlie mined out areas, which can pose a heightened risk of failure and of damages arising out of failure. If one of our impoundments were to fail, we could be subject to substantial claims for the resulting environmental contamination and associated liability, as well as for fines and penalties.
Drainage flowing from or caused by mining activities can be acidic with elevated levels of dissolved metals, a condition referred to as “acid mine drainage,” which we refer to as AMD. The treating of AMD can be costly. Although we do not currently face material costs associated with AMD, it is possible that we could incur significant costs in the future.
These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could materially and adversely affect us.
Risks Related To Our Common Stock
We do not intend to pay dividends on shares of our common stock.
Historically, we have not paid dividends on shares of our common stock and do not anticipate paying any cash dividends on shares of our common stock in the foreseeable future. The terms of the indenture related to our existing credit facilities restrict our ability to pay dividends on shares of our common stock.
We operate in an industry that is subject to significant fluctuations in operating results from quarter to quarter that may result in unexpected reductions in revenue and stock price volatility.
Factors that may influence our quarterly operating results include, but may not be limited to:
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the worldwide demand for coal;
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the price of coal;
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the supply of coal and other competitive factors;
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the costs to mine and transport coal;
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the ability to obtain new mining permits;
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the costs of reclamation of previously mined properties; and
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industry competition.
Due to these factors, it is possible that in some quarters our operating results may be below our shareholders’ expectations and those of public market analysts. If this occurs, the price of our common stock would likely be adversely affected.
Our stock price may decrease, which could adversely affect our business and cause our shareholders to suffer significant losses.
The following factors could cause the market price of our common stock to decrease, perhaps substantially:
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the failure of our quarterly operating results to meet expectations of investors or securities analysts;
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adverse developments in the financial markets, the coal and energy industries and the worldwide or regional economies;
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interest rates;
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changes in accounting principles;
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sales of common stock by existing security holders;
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announcements of key developments by our competitors; and
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the reaction of markets and securities analysts to announcements and developments involving our Company.
If we need to sell or issue additional shares of common stock or assume additional debt to finance future growth, our shareholders’ ownership could be diluted or our earnings could be adversely impacted.
Our business strategy may include expansion through internal growth by acquiring complementary businesses or by establishing strategic relationships with targeted customers. In order to do so, or to fund our other activities, we may issue additional equity securities that could dilute our shareholders’ stock percentage ownership. We may also assume additional debt and incur impairment losses related to goodwill and other tangible assets if we acquire another company which could negatively impact our results of operations.
Our director and officer indemnification policies in conjunction with the provisions of Florida law could result in substantial un-recoupable expenditures and reduced remedies against directors and officers.
Florida Revised Statutes provide for the indemnification of our 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 our behalf. We will also bear the expenses of such litigation for any of our directors, officers, employees, or agents, upon such person’s promise to repay us such amounts, if it is ultimately determined that such person was not entitled to indemnification. This indemnification policy could result in substantial expenditures by us that we will be unable to recoup.
Florida Revised Statutes exclude personal liability of our directors to us and our stockholders for monetary damages for breach of fiduciary duty except in certain specified circumstances. Accordingly, we will have a much more limited right of action against our directors than otherwise would be the case. This provision does not affect the liability of any director under federal or applicable state securities laws.
Item 1B.
Item 1B. Unresolved Staff Comments.
None.
Item 2.
Item 2. Properties
Our executive offices are located at 8915 George Williams Road, Knoxville, Tennessee 37923. We own our corporate office space. The bases of operations for our mining activities are located in Anderson, Campbell and Scott Counties, Tennessee, and Walker, Winston, Marion, Fayette, and Tuscaloosa Counties, Alabama and, until March 31, 2008, in Bell, Harlan and Leslie Counties, Kentucky. We lease office space in Jacksboro, Tennessee and Birmingham, Alabama. We also lease storage space in East Tennessee to house our maps and other geological data. We have pledged our corporate office space as collateral to secure a bank letter of credit issued in favor of the OSM for a portion of one of our reclamation bonds. Additionally, we have granted security interests to our lenders as follows: the obligations under our 10.5% Notes due 2010 are secured by liens on all of our owned and leased mining assets in Tennessee; and the obligations under our 12% Notes due 2012 are secured by liens on all of our owned and leased mining assets in Alabama. These lenders’ security interests in our Tennessee and Alabama assets are mutually exclusive.
Geology
The strata that exist 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 nine coal seams on the New River Tract that we are targeting, and all of these seams are above the water drainage level. There are other coal seams in this area 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 because the terrain generally is more difficult to access and the costs to explore this area are greater than we are willing to expend at this time.
Coal Reserves
“Reserves” are defined by the U.S. Securities and Exchange Commission’s (“SEC”) Industry Guide 7 as that part of a mineral deposit, which could be economically and legally extracted or produced at the time of the reserve determination. “Recoverable” reserves are defined as coal that is economically recoverable using existing equipment and methods under federal and state laws currently in effect. Some of our reserves are classified as proven reserves. “Proven (Measured) Reserves” are defined by the SEC Industry Guide 7 as reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are 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. Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our internal engineers, as well as studies prepared by certified professional geologists based upon data provided by us. “Probable (Indicated) Reserves” for which quantity and grade and/or quality are computed from information
similar to that used for proven (measured) reserves, but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for Proven (Measured) Reserves, is high enough to assume continuity between points of observation. Reserve estimates are updated periodically using geologic data taken from drill holes, adjacent mine workings, outcrop prospect openings and other sources. Coal tonnages are categorized according to coal quality, seam thickness, mineability and location relative to existing mines and infrastructure.
As with most other coal-producing companies in Central and Southern Appalachia, a portion of our coal reserves are controlled pursuant to leases from third party landowners. These leases convey mining rights to the coal producer in exchange for a per ton or percentage of gross sales price royalty payment to the lessor. These leases are not scheduled to expire prior to expiration of projected mining activities. Under current mining plans, we expect that all reported leased reserves will be mined out within the period of existing leases or within the time period of assured lease renewals.
Our reported coal reserves are those that can be economically and legally extracted or produced at the time of their determination. In determining whether our reserves meet this standard, we take into account, among other things, mining methods, seam thickness, previous mining, outcrop variability, and coal quality. We calculated our reserves by relying on measured seam thickness, known coal densities, measured coal acres and anticipated mining methodology minus any previous mining. We have obtained, or we believe we have a high probability of obtaining, all required permits or government approvals with respect to our reserves.
We currently estimate that at December 31, 2008, 40.8 million tons of our proven and probable in-place reserves are recoverable. This estimate takes into account various factors that affect our ability to recover our reserves, including but not limited to current coal prices; the mining methods that may be used to extract particular reserves; geological and mining conditions; historical production from similar areas with similar conditions; the assumed effects of regulations and taxes by governmental agencies; assumptions governing future prices; future operating, development and reclamation costs; and mining technology improvements.
Our reserve estimates are based on geological data assembled and analyzed by our staff of engineers. Reserve estimates will be periodically updated to reflect past coal production, new drilling information and other geologic or mining data. Acquisitions or sales of coal properties will also change our reserves. On October 19, 2007, we acquired Mann Steel which added 6.2 million tons of recoverable coal to our reserves at that time. Changes in mining methods or technology may increase or decrease the recovery basis for a coal seam. Our reserve estimates are subject to change as a result of various factors, including the acquisition, divestiture or depletion of reserves or the future analysis of known or existing data. We engage third parties periodically to review or audit our reserve estimates. The most recent third party audit of certain of our reserves was conducted in 2008 by Marshall Miller & Associates, Inc. in Tennessee, and separately, in Alabama, by Norwest Corporation. Future estimates of our reserves, including estimates prepared by engineering firms, could be materially different from current estimates. There are numerous uncertainties inherent in estimating quantities and qualities of recoverable reserves, including many factors beyond our control.
In addition, we believe that we have unproven deposits that have not yet been classified as reserves. Unproven deposits are coal-bearing bodies that have not been sufficiently sampled and analyzed in trenches, outcrops, drilling, and underground workings to assume continuity between sample points. This coal does not qualify as a commercially viable coal reserve as defined by the SEC Industry Guide 7 until a final comprehensive evaluation based on unit cost per ton, recoverability, and other material factors concludes legal and economic feasibility. Unproven coal deposits may be classified as such by either limited property control or geologic limitations, or both. These unproven deposits are located immediately adjacent to our known reserves. There has been previous mining activity on or near some of these sites, but we have not yet done adequate drilling or other exploration necessary to properly define these areas as reserves.
With respect to our reserve estimates, see “Risk Factors - We face numerous uncertainties in estimating our economically recoverable coal reserves, and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs or decreased profitability.”
We decide on a case by case basis whether to obtain a title review from a licensed attorney prior to purchasing or leasing property. In determining whether to conduct a title review, we will consider information we have about the particular property, including, for example, personal knowledge of our employees or consultants, or historical information from the previous owners, or information obtained from surrounding property owners. We have not obtained title insurance in connection with acquisitions of coal reserves, and generally will not do so in future acquisitions. However, we do have title insurance on our Tennessee properties obtained in conjunction with the issuance of our 10.5% Notes due 2010. We had a title examination made of the New River Tract when we purchased it from Cumberland Timber Company, LLC, and we also have a title policy that was prepared and continues to be updated for properties acquired in Alabama.
The following table provides proven and probable, recoverable reserve data assigned to specific tracts and coal seams as of December 31, 2008:
Quality is provided on a “washed, dry basis” based on an average of samples taken and reported by independent third party engineering firms.
Note: The Peewee seam under the Ketchen Tract has demonstrated reserves of 28,785 tons. The Jagger seam at the Crescent Valley Tract has demonstrated reserves of 16,074 tons.
Maps showing locations of National Coal’s properties are included as Exhibit 99.1 to this Report on Form 10-K.
Item 3.
Item 3. Legal Proceedings.
We are a defendant in a lawsuit in the U.S. District Court for the Eastern District of Tennessee, entitled Sierra Club et al. v. National Coal Corporation, Civil Action No. 3:08-cv-00410, involving claims made by three environmental organizations - Sierra Club, Save Our Cumberland Mountains, and Tennessee Clean Water Network - under the citizens’ suit provisions of the Clean Water Act. In the lawsuit, the plaintiffs assert that National Coal is discharging selenium to waters of the United States without a permit at its Mine No. 7 surface mine in Tennessee, identified as Zeb Mountain throughout the lawsuit. National Coal denies the allegations and is vigorously contesting the matter. Selenium is a naturally-occurring element that is an essential nutrient for many organisms but has toxic effects at elevated concentrations. National Coal has, and at all relevant times has had, a permit issued by the Tennessee
Department of Environment and Conservation for discharge of water from its surface coal mining operations at its Mine No. 7 surface mine. The lawsuit is in the early stages of litigation with the parties engaged in the first steps of discovery. Trial is scheduled for July 2010. Plaintiffs have asked the court to find that National Coal has violated the Clean Water Act by discharging selenium without a permit, to enjoin National Coal from operating the Mine No. 7 surface mine in such a manner as to allow unlawful discharges of selenium, and for civil penalties. If the plaintiffs are successful, then National Coal could incur an unspecified amount of civil penalties. Although the Clean Water Act allows a maximum of $32,500 per day for each violation, the maximum amount is not ordinarily imposed. National Coal also may incur undetermined costs for treatment of water polluted by selenium and/or for costs of remediation to prevent or limit contamination of water by selenium. We believe we have meritorious defenses to all of the claims asserted in this action and will continue to vigorously defend our position; however, we cannot predict the outcome of this proceeding at this time, and cannot predict whether the outcome will have a material adverse effect on our financial condition.
Item 4.
Item 4. Submission of Matters to a Vote of Securities Holders.
None.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Common Stock
Our common stock is listed on the NASDAQ Global Market, trading under the symbol “NCOC”.
The following table sets forth, for the periods indicated, the high and low sales prices for our common stock from January 1, 2007 through December 31, 2008. The following quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission, and may not represent actual transactions.
On March 26, 2009, the closing sales price of our common stock as reported on the NASDAQ Global Market was $1.38 per share. As of March 26, 2009, there were approximately 171 holders of record of our common stock.
Dividends
We are restricted from making cash dividend payments on our common stock under the terms of our 10.5% Notes due 2010. We do not intend to pay dividends on our common stock.
Historically we have made semi-annual cash dividend payments to the holders of our Series A cumulative convertible preferred stock on June 30 and December 31. The dividend rate of our Series A cumulative convertible preferred stock increased from 5% to 8% on September 1, 2006. During the year ended December 31, 2008, we paid $244,405 in dividends to the holder of our Series A cumulative convertible preferred stock.
On October 23, 2008 the holder of 133.33 shares of Series A cumulative preferred stock, representing all of the remaining Series A preferred stock then outstanding, with a liquidation preference totaling $1,999,950, was provided with an inducement and exchanged shares into 499,988 shares of common stock, including 154,573 inducement shares. The value of the inducement shares of $593,563 was recorded as a deemed dividend to reflect the excess of the fair value of the common stock over the fair value of the Series A preferred stock exchanged.
During the year ended December 31, 2007, we accrued dividends to the holders of our Series A cumulative convertible preferred stock of approximately $399,000. We paid approximately $362,886 in dividends to the holders of our Series A cumulative convertible preferred stock in 2006, $413,567 in 2007, and issued 159,152 in common shares in lieu of preferred dividends as a result of the conversion of shares of preferred stock to common stock.
At December 31, 2007, there were accrued but unpaid dividends on our Series A cumulative convertible preferred stock of $114,216. The holders of 342.10 shares of the Series A cumulative convertible preferred stock converted during the year ended December 31, 2007 were provided with an inducement to convert in the form of an additional 431,257 shares of common stock with an aggregate market value of $1,368,029. The holders of 24.0 shares of the Series A cumulative convertible preferred stock converted during the year ended December 31, 2007 were provided with a $53,988 cash inducement to convert. The holders of 223.11 shares of the Series A cumulative convertible preferred stock with liquidation preferences totaling $3,346,650 were provided with a $1,648,168 cash inducement to convert within sixty days of payment of the inducement. The holders used the proceeds of the payment to purchase 558,701 shares of our common stock at $2.95 per share. The same holders converted all 223.11 shares of our Series A cumulative convertible preferred stock plus accrued dividends of $131,712 into 600,753 shares of our common stock on January 15, 2008. The combined $3,070,185 value of these inducements was recorded as a deemed dividend to reflect the excess of the fair value of the common stock over the fair value of the Series A preferred stock exchanged in 2007. This treatment is in accordance with the Financial Accounting Standards Board’s Emerging Issues Task Force Abstract D-42 “The Effect of the Calculation of Earnings per Share for the Redemption or Induced Conversion of Preferred Stock”, which requires that if convertible preferred stock is converted to other securities pursuant to an inducement offer, we should record the excess of (1) the fair value of all securities and other consideration transferred to the holders of the convertible preferred stock over (2) the fair value of securities issuable pursuant to the original conversion terms as an increase to net loss to arrive at net loss attributable to common shareholders.
Performance Graph
The following performance graph compares the yearly percentage change in the cumulative total shareholder return on the common stock of National Coal Corp. to the cumulative shareholder return for the same period of a peer group and the Russell 2000 Stock Index. The peer group is comprised of National Coal Corp., CONSOL Energy, Arch Coal, Inc., and Peabody Energy Corp. The graph assumes that all dividends were reinvested and that the investments were held through December 31, 2008.
The material in this section is not “soliciting material,” and is not deemed “filed” with the SEC and is not to be incorporated by reference into any of our filings under the Securities Act of 1933, as amended, or the Exchange Act.
Item 6.
Item 6. Selected Financial Data.
(1) Consists of certificates of deposit and other cash primarily serving as collateral for reclamation liabilities and an operating lease, deposits for worker’s compensation liabilities, and utility and performance bonds.
(2) Includes coal mineral rights, net of accumulated amortization and depletion. Excludes assets held for sale.
(3) Includes obligations under capital leases.
(4) Adjusted EBITDA is defined as net loss plus (i) other (income) expense, net, (ii) interest expense, (iii) depreciation, depletion, accretion and amortization minus (iv) interest income, (v) income tax benefits, (vi) income from joint ventures and (vii) stock compensation expense. We present Adjusted EBITDA to enhance understanding of our operating performance. We use Adjusted EBITDA as a criterion for evaluating our performance relative to that of our peers, including measuring our cost effectiveness and return on capital, assessing our allocations of resources and production efficiencies and making compensation decisions. We believe that Adjusted EBITDA is an operating performance measure that provides investors and analysts with a measure of our operating performance and permits them to evaluate our cost effectiveness and production efficiencies relative to competitors. In addition, our management uses adjusted EBITDA to monitor and evaluate our business operations. However, Adjusted EBITDA is not a measurement of financial performance under accounting principles generally accepted in the United States of America (“GAAP”) and may not be comparable to other similarly titled measures of other companies. Adjusted EBITDA should not be considered as an alternative to cash flows from operating activities, determined in accordance with GAAP, as indicators of cash flows. The following reconciles our net loss to Adjusted EBITDA:
(5) Average cash cost per ton is calculated as the sum of cost of sales and general and administrative expense (excluding depreciation, depletion, accretion and amortization), divided by the number of produced tons sold. Although average cash cost per ton is not a measure of performance calculated in accordance with GAAP, management believes that it is useful to investors in evaluating us because it is widely used in the coal industry as a measure to evaluate a company’s control over its cash costs. Average cash cost per ton should not be considered in isolation or as a substitute for measures of performance in accordance with GAAP. In addition, because average cash cost per ton is not calculated identically by all companies, the presentation here may not be comparable to other similarly titled measures of other companies. The table below reconciles the GAAP measure of total operating costs and expenses to average cash cost per ton:
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis should be read together with the Consolidated Financial Statements of National Coal Corp. and the Notes to Consolidated Financial Statements included elsewhere in this report. This discussion summarizes the significant factors affecting the consolidated operating results, financial condition, liquidity and cash flows of National Coal Corp. for the fiscal years ended December 31, 2008, 2007 and 2006. Except for historical information, the matters discussed in this Management’s Discussion and Analysis of Financial Condition and Results of Operation are forward-looking statements that involve risks and uncertainties and are based upon judgments concerning various factors that are beyond our control.
We mine, process and sell high quality bituminous steam coal from mines located in East Tennessee, North Alabama and, until March 31, 2008, in Southeastern Kentucky. We own the coal mineral rights to approximately 65,000 acres of land and lease the rights to approximately 17,700 additional acres excluding the Southeast Kentucky properties, known as Straight Creek. We have expanded our operations considerably since commencing operations at a single surface mine in Tennessee in July 2003. As of December 31, 2008, our active mining complexes included three underground mines, one underground mine in the development stage, six surface mines, and one highwall mine. In addition, we have two preparation plants and two unit train loading facilities served by the Norfolk Southern (“NS”) railroad in Tennessee and are a minority partner in the owner of a barge loading facility on the Warrior River in Alabama. We hold permits that allow us to open or re-open seven mines close to our current operations.
As of December 31, 2008, we controlled approximately 40.8 million estimated recoverable tons of coal reserves as defined by SEC Industry Guide 7.
We generated total revenues of $132.6 million, had a net loss of $34.9 million or $1.13 per diluted share for the year ended December 31, 2008, compared to total revenues of $92.8 million, a net loss of $25.8 million or $1.46 per diluted share for the year ended December 31, 2007. We produced 1.8 million tons of coal and sold 2.0 million tons of coal in 2008, compared to 1.4 million tons and 1.8 million tons in 2007, respectively. Also for the year ended December 31, 2008 we had an Adjusted Earnings Before Interest, Taxes, and Depreciation and Amortization (“Adjusted EBITDA”) loss of $0.8 million, compared to Adjusted EBITDA of $0.6 million for the year ended December 31, 2007. See page 38 for a description of Adjusted EBITDA and a reconciliation to net loss. Our revenue per ton of coal sold has increased from $52.15 for the year ended December 31, 2007 to $65.00 for the year ended December 31, 2008, a 25% increase. Approximately 21% of our production for 2008 was produced at underground mines and 79% was produced at our surface and highwall mining operations.
In October 2007, we acquired Mann Steel Products, Inc., now National Coal of Alabama, with mines located in North Alabama for approximately $58.7 million. National Coal of Alabama operates four surface mines, extracting high quality coal on leases encompassing 6.7 million tons of reserves at December 31, 2008 and produced approximately 0.9 million tons of coal during 2008. National Coal of Alabama controls approximately 6.7 million tons of leased reserves at December 31, 2008 and we believe there are additional unproven reserves among the company’s controlled or permitted properties.
Our revenues are derived primarily from the sale of coal to electric utility companies and industrial customers in the Southeastern United States. During the year ended December 31, 2008, approximately 64% of our revenue was generated from coal sales to electric utility companies under long term contracts or open purchase orders with long standing customers. Our largest customers were Georgia Power, Alabama Power, and Solutia, Inc., representing approximately 34%, 21% and 14% of our revenues, respectively.
Since inception, we have expanded our production capacity by actively pursuing the development and permitting of properties acquired through strategic acquisitions in Tennessee and Alabama. We have been able to increase the of market for our coal to customers that may benefit from transportation costs advantages due to the location of our mines and loading facilities. In February 2006, we purchased a 42-mile short line railroad from Norfork-Southern for approximately $2.0 million. This short line railroad which connects our New River reserves and Baldwin facilities to the Norfolk-Southern main line rail facilities at Oneida, Tennessee became operational in the third quarter of 2008. We acquired the Baldwin preparation plant and rail load-out facility in 2005 in return for the assumption of certain reclamation liabilities and spent $7.0 million during 2006 to refurbish and modernize the preparation plant and rail load-out facility. The expenditures made on our transportation and preparation plant infrastructure including the short line railroad and the Baldwin facility reduce our transportation and coal preparation cost and provide us additional opportunities to market coal produced from our owned reserves on the New River tract. When economically advantageous and market conditions are favorable, we also intend to take advantage of our increased production capabilities. Over the longer term, we plan to continue to permit and develop additional properties from our current reserve base while continuing to explore opportunities in nearby areas.
During 2008 we invested $24.1 million in equipment and mine development including $6.9 million purchased through equipment financing arrangements. Of this total, $0.5 million was used to acquire a 524 acre mineral lease in eastern Tennessee that includes approximately 1.4 million tons of recoverable high quality coal. Additionally, we acquired a 1,000 acre mineral and surface tract in eastern Tennessee that includes approximately 2.3 million tons of high quality coal. The purchase price was $7.0 million of which $2.0 million was paid in cash and $5.0 million in the issuance of 756,430 shares of our common stock. We intend to invest approximately $6.3 million in capital expenditures during 2009 to maintain planned production goals and approximately $1.8 million to maintain existing assets.
We sell a majority of our coal pursuant to long-term contracts or open purchase order arrangements with long time customers. Long term contracts as customary in the industry are defined as those with a duration of one year or more. During 2008, we successfully renegotiated several of our existing coal supply agreements resulting in an increased selling price per ton and additional revenues from those contracts. The contracted weighted average selling price per ton is $75.28, $77.40 and $79.43 on 2.1 million, 1.0 million and 0.35 million contracted tons for 2009, 2010 and 2011, respectively. We plan to continue negotiations with existing and new customers to obtain additional sales for the high quality coals from our controlled and permitted properties in Tennessee and Alabama including recently acquired properties.
We have not yet priced a portion of the coal we have the capability of producing over the next several years in order to take advantage of possible future market demand or to realize possible long term opportunities with certain users of high quality reserves we control. At December 31, 2008, our un-priced and uncommitted future production was approximately 0.2 million to 0.3 million tons in 2009, 1.1 million to 1.5 million tons in 2010 and 2.5 million tons in 2011.
During the first quarter of 2008, our dragline equipment utilized on our L. Massey surface mine in Alabama suffered a major mechanical failure. The equipment was repaired, moved to the Poplar Springs mining complex and placed back in production in the third quarter 2008. This breakdown resulted in estimated lost production of 140,000 tons and lost revenues of $9.5 million during the year ended December 31, 2008.
Our financial results from operations depend heavily upon our production costs. Our primary expenses related to production costs are wages and benefits, repairs and maintenance, diesel fuel and other petroleum products, blasting supplies, truck and rail transportation, cost of purchased coal, processing and loading costs, taxes and royalties incurred in selling coal. During 2008, we experienced severe increases in diesel fuel and costs associated with all petroleum related products and also encountered additional regulatory examination, as did most of our competitors, that weakened productivity. Our exploration costs of approximately $1.5 million significantly increased as compared to $0.4 million in 2007 reflecting a full year of National Coal of Alabama exploration costs included in 2008 as compared to only three months in 2007 and ongoing exploration efforts in Tennessee in 2008. We have a full time staff in Tennessee and Alabama that operate drilling rigs in ongoing efforts to identify and prove up additional economically mineable and marketable reserves on our existing controlled properties and other properties we believe may have potential.
On March 31, 2008, our wholly-owned subsidiary, National Coal Corporation, completed the sale of assets that comprise the Straight Creek mining operations in Bell, Leslie and Harlan Counties, Kentucky to Xinergy Corp. (“Xinergy”) for $11.0 million in cash in accordance with the terms and conditions of a Purchase Agreement entered into among the parties on February 8, 2008. As a result of the transaction, we were relieved of approximately $3.6 million in reclamation liabilities, and $2.6 million of equipment related debt which were assumed by Xinergy in the transaction. The sale included property, plant, equipment, and mine development with a net book value of approximately $16.1 million. After a negative working capital adjustment of approximately $288,000, the transaction resulted in a loss of approximately $365,000 which is reflected in other Other income (expense), net on our condensed consolidated statement of operations for the year ended December 31, 2008. Additionally, the transaction resulted in the subsequent release of approximately $7.0 million in restricted cash that was previously pledged to secure reclamation bonds and other liabilities associated with the Straight Creek mining operations. In conjunction with this transaction, we signed a Contract Mining and Services Agreement with Xinergy dated April 1, 2008 to provide highwall mining services to Xinergy at our former properties in Southeast Kentucky for a period of up to twenty-four months. As a result of this sale, in March and April 2008 we used the proceeds from the sale of the Straight Creek, Kentucky properties to repay in its entirety the $10.0 million Term Loan Credit Facility and accrued interest of approximately $102,000 that was entered into in October 2006 with Guggenheim Corporate Funding, L.L.C. The repayment resulted in additional interest expense of $1,168,923 for the year ended December 31, 2008 from the write-off of deferred financing costs associated with the Term Loan Credit facility.
Xinergy was founded and is controlled by Jon Nix, who is a founder and former officer, director and stockholder of National Coal. Mr. Nix served as a director of National Coal Corp. from January 2003 until July 2007, and as Chairman of the Board from March 2004 until July 2007. Mr. Nix also served as our President and Chief Executive Officer from January 2003 until August 2006.
For additional information regarding some of the risks and uncertainties that affect us and our industry, see “Risk Factors.”
Critical Accounting Policies, Judgments and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these consolidated financial statements requires us 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, we evaluate our estimates, including those related to computing depreciation, depletion, amortization, accretion, the basis of reclamation and workers compensation liabilities, asset impairment, valuing 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.
We believe our most critical accounting policies include revenue recognition, the corresponding accounts receivable and the methods of estimating depletion and reclamation expense of actual mining operations in relation to estimated total mineable tonnage on our properties.
Revenue Recognition. Under SEC Staff Accounting Bulletin No. 104, Revenue Recognition, we recognize 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) collectability is reasonably assured. In the case of coal we mine and sell, we negotiate a specific sales contract with each customer, which includes a fixed price per ton, a delivery schedule, and terms for payment. When applicable, freight costs billed to the customers as part of the contract price are included as coal sales with the offsetting expense included in cost of sales. We recognize revenue from sales made pursuant to these contracts at the time the coal is loaded onto rail cars, barges and trucks at our load-out, mine, and processing plant facilities.
Property, Plant, Equipment and Mine Development. Property and equipment are stated at cost. Maintenance and repairs that do not improve efficiency or extend economic life are expensed as incurred. Plant and equipment are depreciated using the straight-line method over the estimated useful lives of assets which generally range from seven to thirty years for building and plant and one to seven years for equipment. On sale or retirement, asset cost and related accumulated depreciation are removed from the accounts and any related gain or loss is reflected in income.
Leasing is used for certain capital additions when considered cost effective relative to other capital sources. All leases with an initial term greater than one year are accounted for under Statement of Financial Accounting Standards, or SFAS, 13, Accounting for Leases. These leases are classified as either capital or operating as appropriate. Leased equipment meeting the capital lease criteria of SFAS 13 is capitalized and the present value of the related minimum lease payments is recorded as a liability. Amortization of capitalized leased assets is computed on the straight-line method over the shorter of the estimated useful life or the initial lease term.
Reserves and mine development costs are recorded at cost or at fair value in the case of acquired businesses. Our coal reserves are controlled either through direct ownership or through leasing arrangements which generally last until the recoverable reserves are depleted. Depletion of reserves and amortization of mine development costs is computed using the units-of-production method over the estimated recoverable tons. Costs related to locating coal deposits and determining the extractive feasibility of such deposits are expensed as incurred.
Exclusive of approximately $55.8 million of net property, plant, equipment, and mine development, that we had recorded as of December 31, 2006, was approximately $0.6 million of mining equipment classified as assets held for sale. This equipment was sold in January 2007 for a small gain.
We review our long-lived assets for impairment when events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. If impairment indicators are present and the future undiscounted cash flows are less than the carrying value of the assets, the carrying values are reduced to the estimated fair value.
Asset Retirement Obligation. The Surface Mining Control and Reclamation Act of 1977 and similar state statutes require that mine properties 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 underground 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, Accounting for Asset Retirement Obligations (“SFAS 143”). We record our reclamation obligations on a mine-by-mine basis based upon current permit requirements and estimated reclamation obligations for such mines as determined by third-party engineering estimates. In accordance with SFAS 143, we determine the fair value of our asset retirement obligations using a discounted cash flow methodology based on a discount rate related to the rates of US treasury bonds with maturities similar to the expected life of a mine, adjusted for our credit standing. In estimating future cash flows, we consider third party profit and apply inflation factors as required by SFAS 143.
On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes granted by state authorities, additional costs resulting from accelerated mine closures, and revisions to cost estimates and productivity assumptions, to reflect current experience.
Stock-Based Compensation. We account for stock-based compensation using Statement of Financial Accounting Standards No. 123 (Revised 2004), Share-Based Payment (“SFAS 123(R)”). We currently use a standard option pricing model to measure the fair value of stock options granted to employees. SFAS 123(R) requires all companies to measure compensation cost for all share-based payments, including employee stock options, at fair value and is effective for interim or annual periods beginning after December 15, 2005. We adopted this standard effective January 1, 2006 and have elected the modified prospective application transition method. Under the modified prospective application transition method, awards that are granted, modified, repurchased, or cancelled after the date of adoption should be measured and accounted for in accordance with the provisions of SFAS 123(R). Awards granted prior to the effective date should continue to be accounted for in accordance with the provisions of SFAS 123(R) with the exception that compensation expense related to unvested options must be recognized in the income statement based on the fair value of the options on the date of grant. SFAS 123(R) also requires the benefits of tax deductions in excess of recognized compensation cost to be reported as a financing cash flow, rather than as an operating cash flow as required under current literature.
Mineral Reserves. We amortize our acquisition costs, development costs, capitalized asset retirement costs and some plant and equipment using the units-of-production method and estimates of recoverable proven and probable reserves. We review these estimates on a regular basis and adjust them to reflect our current mining plans. The rate at which we record depletion also depends on the estimates of our reserves. If the estimates of recoverable proven and probable reserves decline, the rate at which we record depletion increases. Such a decline in reserves may result from geological conditions, coal quality, effects of governmental, environmental and tax regulations, and assumptions about future prices and future operating costs.
Accounting for income taxes. At December 31, 2008, we had federal and state net operating loss carryforwards of $175.6 million. If not utilized, these federal and state net operating loss carryforwards will begin to expire at various dates beginning in 2015. The Tax Reform Act of 1986 limits the use of net operating loss carryforwards in certain situations where changes occur in the stock ownership of a company. In the event we have a change in ownership in the future, utilization of these carryforwards could be limited.
A valuation allowance has been established to reserve the potential benefits of these carryforwards in our financial statements to reflect the uncertainty of future taxable income required to utilize available tax loss carryforwards and other deferred tax assets. FASB Interpretation No. 48, Accounting for Uncertainties in Income Taxes, an interpretation of SFAS No. 109, Accounting for Income Taxes (“FIN 48”) prescribes a comprehensive model for how companies should recognize, measure, present and disclose in their financial statements uncertain tax positions taken or expected to be taken on a tax return. Under FIN 48, tax positions must initially be recognized in the financial statements when it is more likely than not the position will be sustained upon examination by the tax authorities. Such tax positions must initially and subsequently be measured as the largest amount of tax benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the tax authority assuming full knowledge of the position and relevant facts.
We recognize interest and penalties related to uncertain tax positions in income tax expense, which was $0 for 2008, 2007 and 2006.
There are no income tax examinations currently in process. With few exceptions, the Company is no longer subject to U.S. federal examinations or state and local income tax examinations by tax authorities for years before 2003.
Recent Accounting Pronouncements
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurements (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. SFAS 157 applies under other accounting pronouncements that require or permit fair value measurements. SFAS 157 is effective prospectively for fiscal years beginning after November 15, 2007 and interim periods within that fiscal year. The FASB deferred the effective date of Statement No. 157 for one year for nonfinancial assets and liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis. We adopted Statement No. 157 January 1, 2008, with no material impact on our financial position or results of operations.
In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Liabilities - Including an amendment of FASB Statement No. 115 (“Statement No. 159”). Statement No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. Statement No. 159 is effective prospectively for fiscal years beginning after November 15, 2007. We adopted Statement No. 159 January 1, 2008, with no material impact on our financial position or results of operations.
In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141R, Business Combinations (“SFAS 141R”) which becomes effective for acquisitions occurring on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. SFAS 141R establishes principles and requirements for determining how an enterprise recognizes and measures the fair value of certain assets and liabilities acquired in a business combination, including non-controlling interests, contingent consideration, and certain acquired contingencies. SFAS 141R also requires acquisition-related transaction expenses and restructuring costs be expensed as incurred rather than capitalized as a component of the business combination. We expect that SFAS 141R could have an impact on accounting for any businesses acquired after the effective date of this pronouncement.
In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements-An Amendment of ARB No. 51” (“SFAS 160”). SFAS 160 establishes accounting and reporting standards for the non-controlling interest in a subsidiary (previously referred to as minority interests). SFAS 160 would have an impact on the presentation and disclosure of the non-controlling interests of any non wholly-owned businesses acquired in the future. SFAS 160 will be effective for fiscal years beginning after December 15, 2008; earlier adoption is prohibited. We do not expect adoption of SFAS No. 160 to have a material impact on our financial position or results of operations.
In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No. 133” (“SFAS No. 161”) which changes the disclosure requirements for derivative instruments and hedging activities. SFAS No. 161 requires enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. This SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We do not expect adoption of SFAS No. 161 to have a material impact on our financial position or results of operations.
In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS No. 162”). SFAS No. 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles in the United States of America. SFAS No. 162 is effective sixty days following the SEC’s approval of PCAOB amendments to AU Section 411, “The Meaning of ‘Present fairly in conformity with generally accepted accounting principles’ “. We do not expect adoption of SFAS No. 162 to have a material impact on our financial position or results of operations.
Results of Operations
The following table presents consolidated statement of operations data as a percentage of revenues as of December 31 for each of the years indicated:
Comparison of Twelve Months Ended December 31, 2008 and December 31, 2007
In October 2007, we acquired Mann Steel Products, Inc., a company with mining operations in North Alabama for $58.7 million and renamed the company National Coal of Alabama, Inc. National Coal of Alabama operates four surface mines, extracting high quality coal on surface and mineral leases encompassing 6.7 million tons of reserves at December 31, 2008.
On March 31, 2008, our wholly-owned subsidiary, National Coal Corporation, completed the sale of the real and personal property assets that comprise its Straight Creek mining operations in Bell, Leslie and Harlan Counties, Kentucky to Xinergy Corp. (“Xinergy”) for $11.0 million in cash in accordance with the terms and conditions of a Purchase Agreement entered into among the parties on February 8, 2008.
Production
During the year ended December 31, 2008 and 2007, our mines produced 1,830,089 and 1,350,911 tons of coal, respectively, as follows:
The 2008 figures above include 860,604 tons produced by National Coal of Alabama, Inc. and 59,181 tons produced by our Straight Creek Mining operations that were sold in March 2008. The 2007 figures above include 204,740 tons produced by National Coal of Alabama, Inc. and 322,478 tons produced by our Straight Creek mining operations.
Revenue
During the years ended December 31, 2008 and 2007, approximately 88.0% and 89.6% of coal sales were made to four utilities and four industrial customers under contracts and open purchase order arrangements with original terms of twelve months or longer. The remaining coal sales for the period were made under short term contracts or purchase orders. Tons sold and the associated revenue for the period ended follows:
During the twelve months ended December 31, 2008, we generated all of our coal sales revenue from twenty-seven customers, six of which were electric utilities (64%), twenty of which were industrial companies (34%) and one was a coal reseller (2%). Most of our coal sales are derived from contracts of twelve months or longer and open purchase order arrangements with long standing customers.
The 40.7% increase in revenue from coal sales for the year ended December 31, 2008 as compared to the same period in 2007 was primarily the result of:
(i) The addition of National Coal of Alabama, which sold 981,580 tons of coal during the 2008 period at an average price of $68.82 per ton as compared to 204,740 tons of coal sold during the 2007 at an average price of $63.03 per ton; and
(ii) The average selling price for coal sold from the Company’s Tennessee operations increased from $54.30 per ton sold during the 2007 period to $62.72 per ton sold during the 2008 period, while tons sold increased from 817,297 tons in 2007 to 908,320 tons in 2008; reduced by
(iii) The sale of the Straight Creek mining operations, which sold 740,989 tons at an average price of $46.77 during the 2007 period as compared to 100,878 tons sold during the 2008 period at an average price of $48.12 per ton.
The increase in other revenues of $2.4 million consisted primarily of:
(i) Revenue from a contract mining services agreement between Xinergy and National Coal Corporation to mine coal from a highwall mine previously sold to Xinergy as part of the Straight Creek sale on March 31, 2008.
(ii) Through put fees charged to another coal producer for use of our train loading facilities in Southeast Kentucky, which were sold on March 31, 2008; and
Cost of sales
Total cost of sales increased 42.3% during the year ended December 31, 2008 as compared to the same period in 2007 due primarily to:
(i) The addition of National Coal of Alabama, which sold 981,580 tons of coal at an average cost of $61.51 per ton sold compared to only 204,740 tons sold during 2007 at an average cost of $46.41 per ton sold. The $15.10 increase in average cost per ton sold is due principally to increased per ton costs in the areas of labor, purchased coal, freight and hauling, explosives and royalty fees. Additionally, the March 2008 mechanical failure of our dragline equipment resulted in lost production and corresponding revenues of approximately 140,000 tons and $9.5 million, respectively, during the year ended December 31, 2008, further tightening our margins in Alabama.
(ii) Our Tennessee mines sold 908,320 tons at an average cost per ton sold of $62.05 per ton for the year ended December 31, 2008 compared to 817,297 tons at an average cost per ton sold of $52.18 for the year ended December 31, 2007. This increased cost per ton sold of $9.87 is due principally to: (i) $3.57 increased per ton labor cost; (ii) $2.67 increased per ton diesel fuel cost; (iii) $1.84 increase per ton contract labor cost; (iv) $0.73 increase per ton worker’s compensation cost, due principally to an outlier claim in 2008; and (v) $0.50 increase per ton explosives costs.
(iii) The aforementioned increases were offset by the sale of our Kentucky operations, which sold 100,878 tons at a cost of $64.35 per ton for the year ended December 31, 2008 compared to 740,989 tons sold at a cost of $46.45 per ton for the same period in 2007.
The increase in cost of services is due to the contract mining agreement between Xinergy and National Coal Corporation to mine coal from a highwall mine previously sold to Xinergy as part of the Straight Creek sale on March 31, 2008.
Depreciation, depletion, accretion and amortization expense
The 9.7% decrease in depreciation, depletion, amortization, and accretion expense for the year ended December 31, 2008 as compared to the comparable period in 2007, is attributable primarily to:
(i) The sale of approximately $16.1 million in property, plant, equipment, and mine development, and a resulting decrease of $3.7 million of corresponding expense, associated with the sale of the Straight Creek properties on March 31, 2008.
(ii) The reduction in expense of approximately $2.1 million for Tennessee, principally due to assets that were fully depreciated in 2007.
(iii) The addition of National Coal of Alabama which sold 981,580 tons of coal during the 2008 period with an associated average cost of depreciation, depletion, amortization, and accretion per ton of $6.19, or $6.1 million of corresponding expense compared to $1.9 million in expense or average cost of depreciation, depletion, amortization, and accretion of $9.11 per ton during the 2007 period. The decrease in per ton sold is due principally to a $1.4 million gain on settlement of asset retirement obligations recorded in 2008.
General and administrative expenses
The 24.1% increase in general and administrative expenses for the year ended December 31, 2008 as compared to the same period in the previous year is primarily attributable to:
(i) The increase in expenses of $2.0 million associated with National Coal of Alabama with total general and administrative expenses of $2.3 million in 2008 including approximately $0.4 million in bad debt and professional fees of $0.1 million compared to $0.3 million in 2007.
(ii) The addition of estimated legal settlement fees of $0.3 million, bad debt of $0.1 million and professional fees of $0.6 million offset by the reduction in insurance fees of $0.2 million, purchased coal fees of $0.6 million and engineering consulting fees of $0.1 million in our Tennessee operations.
Other Income (Expense)
The 69.4% increase in interest expense for the year ended December 31, 2008 as compared to the same period in 2007, was primarily the result of:
(i) the October 19, 2007 issuance of our 12.0% senior secured notes, the proceeds of which were used to purchase Mann Steel Products, Inc; and
(ii) less a reduction in interest expense on our 10.5% senior secured notes attributable to the conversion of $13.0 million in notes and $158,958 in accrued interest for 1,855,935 shares of our common stock during 2008; and
(iii) the repayment of the $10.0 million term loan credit facility with Guggenheim.
Interest income declined from $1.3 million during the year ended December 31, 2007 to $1.0 million in 2008 as a result of lower average cash balances within our Tennessee operations in restricted cash and operating funds of $0.5 million offset by the addition of National Coal of Alabama with interest income of $0.2 million for the year ended December 31, 2008.
Other income (expense) decreased $2.8 million for the year ended December 31, 2007 compared to the year ended December 31, 2008 primarily due to:
(i) the loss on extinguishment of debt resulting from the $13.0 million reduction in debt on our 10.5% senior secured notes of $0.5 million and the loss resulting from the repayment of our Term loan credit facility of $1.2 million; and
(ii) the loss on sale of assets of $0.3 million primarily related to the sale of our Straight Creek operations on March 31, 2008.
Income from joint venture increased $0.5 million over 2007 due to the investment, through our subsidiary National Coal of Alabama, of Powhatan Dock, LLC (“Powhatan”), during November 2007 representing a 49% interest in Powhatan.
Comparison of Twelve Months Ended December 31, 2007 and December 31, 2006
In October 2007, we acquired Mann Steel Products, Inc. and changed its name to National Coal of Alabama (“NCA”). We have included in our consolidated financial statements the sales and costs attributable to NCA for the period from October 20 through December 31, 2007 which activity has a direct effect on the percent change in statement of operations captions for the year ended December 31, 2007. Prior to acquiring NCA, our National Coal Corporation (“NCC”) subsidiary operated our Tennessee and Kentucky mining operations.
Production
Revenues
For the twelve months ended December 31, 2007, our revenues were derived from coal sales to twenty-three customers, seven of which were electric utilities, fifteen of which were industrial customers and one of which was a coal reseller. Our three largest customers represented 65% of our total coal sales. In 2006 and 2007, coal prices in Central Appalachia declined as a result of mild weather in the Southeast, before showing signs of significant increases in late 2007 and early 2008.
National Coal of Alabama, our newly acquired subsidiary, sold 204,740 tons of coal sales from October 20, 2007 through December 31, 2007 at a total price of $12,904,229 included in the above and represents net increase in coal sales and total revenue before considering decreases in Tennessee and Kentucky. Coal sales attributable to our Tennessee and Kentucky operations are as follows:
The approximately $7.2 million decline in revenue from coal sales from our Tennessee and Kentucky operations in 2007 was partially the result of an 84,289 ton decline in shipments as existing sales agreements expired and sales opportunities at attractive prices were unavailable, in conjunction with a $2.14 per ton decline in average sales price as a result of a softening coal market over the late 2006 and early to mid-2007 period. Two years of unseasonably mild weather resulted in decreased demand for coal reducing prices during those periods.
The increase in other revenues of $150,287 is primarily due to the increase in receipt of loading fees of $124,000 from a coal company with property located adjacent to our Straight Creek, Kentucky operations which were sold on March 31, 2008.
Operating Expenses
Cost of sales
Cost of sales consisted primarily of salary, benefits, and other compensation costs paid directly to miners, and direct costs paid to third party vendors whose goods and services were directly used in the process of producing coal inventory. Third party vendor costs include equipment leases and maintenance costs, blasting costs, fuel costs, parts and supplies, coal purchases, and transportation costs.
NCA incurred $9,501,700 in cost of sales from October 20 through December 31, 2007 increased consolidated cost of sales. At our Tennessee and Kentucky operation, we experienced a $2.3 million decrease in cost of sales, or 2.9% when compared to 2006. On a per ton basis, cost of sales at our Tennessee and Kentucky operation increased $1.14 or 2.3% when compared to 2006.
During 2007, our Tennessee and Kentucky operations produced 172,192 fewer tons than in 2006 relying instead on increased purchases of coal from third parties. As a result, overall production costs at these operations decreased $2.3 million, offset by a $0.8 million increase in the cost of purchased coal. We experienced significant increases in the prices we pay for the products and services we use in our operations such as diesel fuel, tires, blasting services, roof bolts, health insurance, workers’ compensation costs and the per ton fees we pay to contract miners. However, by placing less reliance on contract miners and producing more tons on owned reserves in the New River Tract which do not result in royalty payments to lessors we were able to minimize the effect of the increases on our per ton cost of sales to only $0.09 excluding a $1.05 per ton increase in the cost of sales effect of purchased coal.
Depreciation, depletion, accretion and amortization expense
NCA reflected depreciation, depletion, accretion and amortization expenses from October 20 through December 31, 2007 of $1,864,430. At our Tennessee and Kentucky operations, we experienced a $702,000 decrease in depreciation, depletion, accretion and amortization expenses or 4.6% when compared to 2006. On a per ton basis, depreciation, depletion, accretion and amortization expenses increased by $0.06, or approximately 1% when compared to 2006 due to the decline in tons sold. The decrease in expense is primarily attributable to the late 2006 sale-leaseback of a highwall miner and to certain equipment still in service which was fully depreciated during 2007. This was offset by capital expenditures of approximately $10.9 million in 2007.
General and administrative expenses
General and administrative expenses primarily include non-operations salary, benefits and related expenses; consulting expenses; legal and professional fees; insurance expenses; and travel and travel related expenses.
NCA reflected incremental general and administrative expenses from October 20 through December 31, 2007 of $66,592. At our Tennessee and Kentucky operations, we experienced a $2.3 million decrease in general and administrative expenses or 24.7% when compared to 2006. On a per ton basis, general and administrative expenses at our Tennessee and Kentucky operations decreased by $1.16, or 20.6%when compared to 2006. General and administrative expenses decreased during the period due to targeted efforts to reduce cost. General and administrative labor decreased approximately $1.1 million primarily due to the accelerated vesting of stock options in 2006 and a 3.6% decline in base wages at the corporate level. Other significant reductions were made in consulting and professional services ($318,000), facilities and security ($226,000), insurance costs ($203,000), and travel ($102,000).
Other Income (Expense)
NCA interest expense for the period of October 20 through December 31, 2007 is $1,774,898 incurred on the 12% Notes due 2012. National Coal Corp. and NCC, excluding NCA, incurred interest expense of $8,990,387, an increase of $1,514,563 or 20.3% when compared to the interest expense incurred by the companies in 2006. The increase for the period is primarily attributable to a full year of interest on the Term Loan Credit Facility versus approximately 3 months in 2006 and the increase in rates on that facility due to loan modifications during the year. Rates on the Term Loan Credit Facility increased from approximately 9% in the first quarter, to approximately 10% in the second quarter to 12% beginning in August 2007.
NCA interest income for the period of October 20 through December 31, 2007 was $118,286 earned on bank balances and restricted cash in money market funds securing reclamation bonds. Excluding NCA, we earned interest of $1,179,458, an increase of $387,606 or 48.9% when compared to 2006, as a result of increased average balances.
NCA had no other income (expense) during the post-acquisition period except for the 49% equity interest in the net loss of Powhatan Dock, LLC, an equity method investee, totaling a loss of $41,077 for the year ending December 31, 2007.
Related Transactions
See “Certain Relationships, Related Transactions and Director Independence” included elsewhere in this report for a full description of transactions to which we were or will be a party, in which the transaction involved exceeds a material amount, and in which any director, executive officer, shareholder of more than 5% of our common stock or any member of their immediate family had or will have a direct or indirect material interest.
Liquidity and Capital Resources
At December 31, 2008, we had cash and cash equivalents of approximately $4.6 million and negative working capital of approximately $6.0 million. Cash flows used in operations were $4.8 million, $8.1 million and $3.8 million for the years ended December 31, 2008, 2007 and 2006, respectively. At December 31, 2008, we had stockholders’ equity of $5.5 million and incurred net losses of $34.9 million (excluding preferred stock dividends) for the year then ended. Management expects that we may continue to incur net losses in the future, which would decrease stockholders’ equity and could lead to an eventual stockholders’ deficit.
Management believes that we have sufficient resources to fund our operations through 2009. However, this belief is predicated on certain assumptions as to: (i) sales volumes and related pricing, (ii) production levels, (iii) the availability of coal to be purchased at a reasonable price; (iv) budgeted capital expenditures; and (v) cost per ton level decreases at existing mines and newly opened mines. Significant deviation from any one of these assumptions could have a material adverse effect on our operating cash flows and the ability for our wholly-owned subsidiary National Coal of Alabama, Inc. (“NCA”) to meet certain debt covenants. Management believes that NCA will be in compliance with its debt covenants during 2009. However, there can be no assurances that a debt covenant violation will not occur, or that we will have sufficient cash to satisfy our obligations.
The agreements governing our outstanding senior debt impose a number of restrictions, the most significant of which is the inability to loan funds or infuse capital between NCA and National Coal Corp. Additionally, the terms of our credit facilities contain financial and other covenants that create limitations on our ability to affect acquisitions or dispositions, incur additional debt and may require us to maintain various financial ratios and comply with various other financial covenants. In the second, third and fourth quarters of 2008, NCA failed to meet certain financial covenants required under its 12% Notes due 2012. In each instance, waivers of covenant failures and modifications of future financial covenants were obtained. With respect to the second and fourth quarter waivers only, NCA was charged penalties of $300,000 each quarter for covenant waiver and modification. NCA’s ability to comply with these restrictions may be affected by events beyond its control and, as a result, it may be unable to comply with these restrictions. A failure to comply with these restrictions could adversely affect our ability to borrow under a new credit facility or result in an event of default under these agreements. In the event of a default, NCA’s lenders could terminate their commitments to them and declare all amounts borrowed, together with accrued interest and fees, immediately due and payable. If this were to occur, NCA might not be able to pay these amounts, or could be forced to seek an amendment to its financing arrangements which could make the terms of these arrangements more onerous. As of December 31, 2008, neither we nor NCA have a revolving credit agreement for working capital in place.
We rely primarily on our ability to generate cash from operations to service our debt. If we do not generate sufficient cash flows to meet our debt service, we may need to seek additional financing, the availability of which is uncertain given the current state of credit markets and restrictions in the Company’s existing borrowing agreements. The Company’s financial condition at the time additional funds are being sought may also impact the availability of credit. If we are unable to obtain financing on terms that are acceptable to us amidst the tightening credit market, we could be forced to raise equity financing or sell assets to make up for any shortfall in our payment obligations under unfavorable circumstances. The 10.5% Notes due 2010 and the 12% Notes due 2012 limit our ability to sell assets and also restrict the use of the proceeds from any such sale. However, these debt facilities do allow asset sales if the funds generated from such sales are used to pay outstanding debt and prepayment costs associated with these debt obligations. Even if asset sales are permitted, we may not be able to sell assets in a timely manner or for sufficient amounts to enable them to meet our debt obligations.
We do not believe that we will be able to generate from operations the amount of cash necessary to pay in December 2010 the principal amounts of our 10.5% Notes due 2010. The outstanding principal balance of this indebtedness at December 31, 2008 was $42,000,000. We intend to refinance this indebtedness prior to its maturity by incurring additional debt, the availability of which is uncertain given the current state of credit markets. If we are unable to refinance this indebtedness, we would be required to repay this indebtedness from other sources, including cash raised from equity financings or sales of assets, which may occur under unfavorable circumstances.
During the year ended December 31, 2008, we generated total revenues of $132.6 million and sold approximately 2.0 million tons of coal. Our revenues are derived primarily from the sale of coal to electric utility companies and industrial customers in the Southeastern United States pursuant to long-term contracts or open purchase order arrangements with long-time customers. Long-term contracts as are customary in the industry, are those with a contract duration of one year or more. Our largest customers were Georgia Power, Alabama Power, and Solutia, Inc., representing approximately 34%, 21% and 14% of its revenues, respectively.
During 2008, we successfully renegotiated several of our existing coal supply agreements resulting in an increased selling price per ton and additional revenues from those contracts. The weighted average selling price per ton is $75.28, $77.40, and $79.43 on 2.1 million, 1.0 million, and 0.35 million tons contracted for 2009, 2010, and 2011, respectively. We typically sell our coal for a specified per ton amount and at a negotiated price pursuant to both short-term contracts and contracts of twelve months or greater. For the year ended December 31, 2008, 88% of sales were pursuant to contracts of twelve months or greater. Price adjustment, “price reopener” and other similar provisions in long-term supply agreements may reduce the protection from short-term coal price volatility traditionally provided by such contracts. Any adjustment or renegotiation leading to a significantly lower contract price would result in decreased revenues and lower gross margins, which could have a material adverse effect on our operating cash flows. Additionally, our customers may have the ability to delay the timing of their purchases, which could negatively impact operating cash flows. Finally, coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or our customers during the duration of specified events beyond the control of the affected party.
We have not yet priced a portion of the coal we have the capability of producing over the next several years in order to take advantage of possible future market demand or to realize possible long term opportunities with certain users of the high quality coal contained in our reserve base. At December 31, 2008, our un-priced and uncommitted future production was approximately 0.2 million to 0.3 million tons in 2009, 1.1 million to 1.5 million tons in 2010, and 2.5 million tons in 2011. For 2009, we have assumed we will be able to achieve a minimum spot rate on unpriced tons. If we are unable to obtain this rate, we will reduce production.
We assume we will meet our contract commitments through a combination of produced tons and purchased coal. Our ability to produce tons can be negatively impacted by weather, labor shortages or equipment breakdowns. Additionally, geological and mining conditions may not be fully identified by available exploration data or may differ from experience in current operations. During 2008, we experienced severe increases in diesel fuel and costs associated with all petroleum related products and also encountered additional regulatory examination, as did most of our competitors, that weakened productivity. The Company experienced equipment failure in 2008 which negatively impacted the tons of coal produced and therefore sold. Additionally, coal for purchase may not be available, or available only at unfavorable prices. The occurrence of such events can adversely affect production, the cost of sales or both, and could have a material adverse effect on our operating cash flows.
We invested approximately $24.1 million in equipment and mine development during the year ended December 31, 2008 including $6.9 million purchased through equipment financing arrangements. Management has estimated capital expenditures for 2009 to be $6.3 million to expand operations and approximately $1.8 million to maintain existing assets. We expect to finance $6.3 million of these capital expenditures in 2009. If financing is unable to be obtained, this could negatively impact planned production levels. During the first quarter of 2008, our dragline equipment utilized in our L. Massey surface mine in Alabama suffered a major mechanical failure. The equipment has since been repaired and was back in production during the third quarter of 2008. This breakdown resulted in estimated lost production of 140,000 tons and lost revenues of $9.5 million during the year ended December 31, 2008. In prior years, we also experienced the unanticipated loss of the use of a highwall miner, which resulted in lost production and lost revenues. We may experience similar mechanical failures in the future, which could have a material adverse effect on our operating cash flows.
Acquisition of Mann Steel Products, Inc.
On October 19, 2007, we acquired all of the outstanding stock of Mann Steel Products for an aggregate purchase price of $55,000,000 in cash, paid primarily to the sellers except for $7,406,745 which was retained to repay certain indebtedness of Mann Steel that existed at closing. Mann Steel became a wholly-owned subsidiary of NCC Corp. and changed its name to National Coal of Alabama, Inc. The Purchase Agreement required a working capital adjustment to the purchase price within 30 days after closing. The working capital adjustment required that a determination be made by the Seller’s accounting firm as to the value of working capital, or current assets minus current liabilities, at the closing date, and that the purchase price be increased to the extent working capital exceeded zero, or decreased to the extent working capital was less than zero. As a result of this provision, NCA paid $3,281,313 to the sellers on December 19, 2007. Total cash consideration was $58,660,706 which includes acquisition costs of $379,393.
We funded the acquisition through the combination of two transactions: a) a sale of 3,866,968 shares of National Coal Corp. common stock at $3 per share for a total consideration of $11,600,904 and b) the issuance of the 12% Notes due 2012 in a principal amount of $60 million, for a total of $71,600,904. Amounts were also used within NCA to post collateral for reclamation bonds, pay fees and costs and for general corporate purposes.
National Coal of Alabama, Inc. is restricted in its ability to distribute cash to our other consolidated companies for use in their operations under the terms of our 12% Notes due 2012. On an annual basis, National Coal of Alabama can distribute cash for use in our other operations only if it meets certain EBITDA-based operating requirements for the immediately preceding fiscal year. Additionally, our subsidiary, National Coal Corporation, has entered into a management services agreement with National Coal of Alabama, Inc. that compensates National Coal Corporation for services that it provides to National Coal of Alabama, and a tax sharing agreement that requires National Coal of Alabama to make payments to us in respect of its tax liability. For fiscal 2009, we anticipate National Coal of Alabama’s operations to provide limited cash for use in our other operations.
Due primarily to the loss of production and corresponding revenues associated with the dragline equipment failure, we violated our loan covenants related to our 12% Senior Secured Notes due 2012 (Note 8) in the second, third and fourth quarters of 2008. On August 13, 2008, November 12, 2008 and March 23, 2009, respectively, we received waivers of all existing defaults and covenant violations and obtained amended terms for certain covenants through December 31, 2009.
Sale of Kentucky Properties
On November 13, 2007 National Coal Corporation received $2,000,000 from the sale of certain real property and mineral leases at Pine Mountain, an idle mining complex located in Kentucky, and an additional $1,000,000 from the sale to the same purchaser of an option entitling it to purchase for $10.00 additional properties at Pine Mountain. The sale of certain real property and mineral leases resulted in a gain of approximately $745,000.
On March 31, 2008, our wholly-owned subsidiary, National Coal Corporation, completed the sale of the real and personal property assets that comprised our Straight Creek mining operations in Bell, Leslie and Harlan Counties, Kentucky to Xinergy Corp. for $11,000,000 in cash in accordance with the terms and conditions of a purchase agreement entered into among the parties on February 8, 2008. In addition to our receipt of the purchase price for the assets, the transaction also resulted in the return to us of approximately $7,400,000 in cash that we previously pledged to secure reclamation bonds and other liabilities associated with the Straight Creek operation, and relieved us of approximately $3,600,000 in reclamation liabilities and approximately $2,700,000 of equipment related debt which were assumed by Xinergy in the transaction. The sale resulted in an immaterial loss.
We used a portion of the sale proceeds to repay the $10,000,000 senior secured credit agreement we entered into in October 2006 with Guggenheim Corporate Funding, LLC, as administrative agent, which indebtedness otherwise would have matured in December 2008.
Xinergy Corp. was founded and is controlled by Jon Nix, who is a founder and former officer and director of National Coal. Mr. Nix served as a director of National Coal Corp. from January 2003 until July 2007, and as our Chairman of the Board from March 2004 until July 2007. Mr. Nix also served as our President and Chief Executive Officer from January 2003 until August 2006.
Debt Reduction
During the year ended December 31, 2008, certain holders of our 10.5% Senior Secured Notes exchanged $13,000,000 in notes and $161,780 in accrued interest for 1,855,935 shares of our common stock resulting in a $504,393 loss on extinguishment of debt included as a component of Other within Other income (expense), net in the accompanying condensed consolidated statement of operations.
Debt Obligations
The following table summarizes our long-term debt obligations, excluding capital leases, as of the dates indicated:
12% Notes Payable Due in 2012
On October 19, 2007, NCA completed $60 million in private placements through the issuance of Senior Secured Notes (the “12% Notes due 2012”) to TCW Energy Fund XIV, L.P., TCW Energy Fund XIV-A, L.P. and TCW Energy Fund XIV (Cayman), L.P. pursuant to a note purchase agreement dated October 19, 2007, among NCA, the Holders and TCW Asset Management Company (“TAMCO”). The 12% Notes due 2012 have a maturity date of October 19, 2012 and accrue interest at the rate of 12% per annum due quarterly. In lieu of paying interest due on the 12% Notes due 2012 on each quarterly payment date in full in cash, NCA may elect to pay a portion of such interest in cash equal to the amount of interest which would be owing on such quarterly payment date if the interest rate had been 9% per annum, and to borrow the remaining portion from the Holders in the form of additional loans made through the increase of the principal amounts of the 12% Notes due 2012 (the “PIK election”). NCA did not make the PIK election in 2008.
NCA violated its loan covenants related to its 12% Senior Secured Notes due 2012 in each of the second through fourth quarters of 2008 and waivers were received of all existing defaults and covenant violations on August 13, 2008, November 12, 2008, and March 26, 2009, respectively. Additionally, on March 26, 2009, the credit facility was amended to modify or eliminate certain financial covenant requirements through December 31, 2009, as follows:
(i) the fixed charge coverage ratio minimum requirement of 1.00 to 1.00 has been reduced for all fiscal quarters in 2009 to minimum requirements of 0.65 to 1.00 for the fiscal quarter ending March 31, 2009 and 0.75 to 1.00 for each fiscal quarter ending June 30, 2009, September 30, 2009 and December 31, 2009; and
(ii) the current ratio minimum requirement of 1.00 to 1.00 has been reduced for all fiscal quarters in 2009 to minimum requirements of 0.65 to 1.00 for the fiscal quarter ending March 31, 2009 and 0.80 to 1.00 for each fiscal quarter ending June 30, 2009, September 30, 2009 and December 31, 2009; and
(iii) the minimum EBITDA requirement has been reduced from $3,000,000 for the fiscal quarter ending December 31, 2008 to minimum requirements of $2,000,000 for the fiscal quarter ending March 31, 2009 and $2,250,000 for each fiscal quarter ending June 30, 2009, September 30, 2009 and December 31, 2009; and
(iv) the Debt to EBITDA ratio requirement set forth in the Note Agreement has been eliminated for the fiscal quarters ending March 31, 2009, June 30, 2009, September 30, 2009 and December 31, 2009; and
(v) in lieu of paying interest due March 29, 2009, NCA has elected to borrow the full amount of the interest from the holders in the form of a PIK (“Payment in Kind”) loan in principal amount equal to such interest of approximately $1.8 million.
Management believes that it is probable NCA will be in compliance with its debt covenants through December 31, 2009, and have accordingly classified the related debt as long-term in the accompanying consolidated balance sheet.
On each quarterly payment date from and after March 2008, NCA is required to make a principal payment in respect of the 12% Notes due 2012 in an aggregate amount equal to the adjusted net cash flow for the applicable quarter (as specified in the note purchase agreement), provided that in no event shall NCA be required to make a payment that results in its having cash and cash equivalents (exclusive of any cash and cash equivalents that have been pledged to secure other obligations permitted under the note purchase agreement or that otherwise constitutes “restricted cash” permitted under the note purchase agreement) of less than $2,000,000. NCA is also required to repay outstanding amounts upon the sale of collateral approved by the Holders of a majority of the aggregate unpaid principal amount under the 12% Notes due 2012 and upon the receipt of certain casualty insurance proceeds. In addition, NCA will be required to pay a “make-whole” amount or incur a prepayment premium in the event that it prepays the Notes prior to their stated maturity. During 2008, NCA was not required to make any payments pursuant to the aforementioned provisions, nor do we expect any such payments to be made in 2009.
Pursuant to the terms of the note purchase agreement and related security and pledge agreements, all dated October 19, 2007, NCA granted the holders a security interest in all of our assets to secure repayment of the obligations arising under the note purchase agreement and related agreements, and established a debt service reserve account equal to six months of interest on the then outstanding aggregate principal amount of the Notes. The 12% Notes due 2012 are not guaranteed by National Coal Corp., National Coal Corporation or its subsidiaries.
As additional consideration to the holders, NCA conveyed to the Holders an Overriding Royalty Interest with respect to all coal mined by NCA in the state of Alabama. Pursuant to the Conveyance of Overriding Royalty Interest, dated October 19, 2007, NCA agreed to pay the holders of the interest a royalty on 18.5 million tons of coal mined and sold by NCA, in an amount equal to (i) $2.00 per ton of coal mined and sold annually, subject to a one million ton minimum, while the obligations remain outstanding under the note purchase agreement, and (ii) an amount equal to 1% of the gross sales price of coal mined and sold after repayment of the obligations under the note purchase agreement. The present value of the expected cash flows associated with the Overriding Royalty Interest, estimated at $9,321,873, reflecting a discount rate of 16.83%, was recorded as a liability and as a discount to the 12% Notes due 2012 on the purchase date. During 2008, NCA recorded an additional $0.5 million of interest expense associated with a change in estimate of its future overriding royalty obligation. Additionally, NCA was required to pay a $0.2 million penalty for not meeting the one million ton annual minimum tons mined and sold.
NCA also paid to TAMCO a commitment fee of $900,000, which is equal to 1.5% of the aggregate commitments of $60 million under the note purchase. Fees were also paid of $1.1 million and 175,000 shares of our common stock to a broker who assisted with this transaction. These amounts were recorded as deferred financing costs in the accompanying balance sheets.
Each of NCC Corp. and NCA is an “unrestricted subsidiary” within the meaning of our 10.5% Senior Secured Notes due 2010, which means that: (i) these unrestricted subsidiaries cannot have any indebtedness for which National Coal Corp. or any of its other subsidiaries is directly or indirectly liable, or which National Coal Corp. or any of its other subsidiaries guarantees or otherwise provides credit support; (ii) these unrestricted subsidiaries cannot be party to any agreement with National Coal Corp. or any of its other subsidiaries unless the terms of any such agreement are no less favorable to National Coal Corp. or such other subsidiaries than those that might be obtained at the time from persons who are not our affiliates; (iii) none of National Coal Corp. or its other subsidiaries can have any direct or indirect obligation to subscribe for additional equity interests of the unrestricted subsidiaries or maintain or preserve the unrestricted subsidiaries’ financial condition or cause them to achieve any specified levels of operating results.
National Coal of Alabama, Inc. is restricted in its ability to distribute cash to the other subsidiaries of the Company and to the Company for use in their operations under the terms of the TCW credit facility. On an annual basis, National Coal of Alabama can distribute cash for use in our operations only if it meets certain EBITDA based operating requirements for the immediately preceding fiscal year. Additionally, our subsidiary, National Coal Corporation, has entered into a management services agreement with NCA that compensates National Coal Corporation for services that it provides to National Coal of Alabama, and a tax sharing agreement that requires NCA to pay to the Company 75% of its tax liability. In fiscal 2009, however, we anticipate cash provided from NCA’s operations to be limited to the management services fee.
Term Loan Credit Facility
On October 12, 2006, our wholly-owned subsidiary, National Coal Corporation, entered into a Term Loan Credit Facility that provides for borrowings of $10.0 million with Guggenheim Corporate Funding, LLC to fund general operating and working capital needs (the “Term Loan Credit Facility”). We borrowed $8.0 million in 2006, and $2.0 million in March 2007. Our obligations under the credit facility are secured by a first priority senior lien on substantially all of our assets.
Initially, the credit agreement provided that all amounts under the facility would be due and payable in March 2010 and would bear interest at a rate equal to, at the our option, the Eurodollar Rate plus 3.5% or the Base Rate (which approximates the prime rate) plus 2.5%. The term loan credit facility also contained financial covenants and default provisions including that we maintain minimum levels of EBITDA and liquidity, maintain minimum interest coverage ratios, not exceed maximum leverage ratios, and that it limit certain future categories of transactions such as the incurrence of additional indebtedness and the sale of assets.
In March 2007, Guggenheim agreed to amend the credit agreement and reset the financial covenants, as a result of which the applicable margin on the credit facility was increased by 1.0%. At June 30, 2007, we were not in compliance with certain financial covenants under the credit agreement and on August 15, 2007, Guggenheim agreed to a further amendment under which (1) the maturity date was changed to December 31, 2008, (2) the interest rate was changed to 12%, (3) fees equal to 5% of all balances outstanding at December 31, 2007 and 10% of all amounts outstanding at June 30, 2008 were provided for, (4) the EBITDA financial covenant was reset, and (5) prepayment penalties were eliminated.
On October 19, 2007, the lenders party to the credit agreement assigned to Steelhead Offshore Capital, LP, Big Bend 38 Investments, L.P., and J-K Navigator Fund, L.P., our outstanding obligations to repay funds loaned to us pursuant to the credit agreement in the aggregate principal amount of $10,000,000 and, to the extent permitted to be assigned under applicable law, all claims, suits, causes of action and any other right of the lenders against any person arising under or in connection with the credit agreement. Guggenheim remained as Administrative Agent under the credit agreement.
On October 19, 2007, the parties to the credit agreement entered into a Waiver and Amendment No. 3 to the credit agreement, pursuant to which the parties agreed to waive and amend certain provisions of the credit agreement. Pursuant to the waiver and amendment, Guggenheim and each lender waived certain fees related to amounts outstanding under the term loan facility as of December 31, 2007, our compliance with certain minimum consolidated EBITDA requirements for the fiscal quarters ending September 30, 2007 and December 31, 2007, and the registration and processing fee due to Guggenheim solely with respect to the assignment and acceptance of our outstanding obligations to Steelhead Offshore Capital, LP, Big Bend 38 Investments, L.P., and J-K Navigator Fund, L.P. The waiver and amendment also amended various restrictive covenants in the credit agreement, including covenants to permit us to consummate the acquisition of Mann Steel Products, Inc. and incur the debt financing for such acquisition. Fees equal to 10% of all amounts outstanding under the credit agreement at June 30, 2008, provided for in the second amendment dated August 15, 2007, remain in place. We did not accrue any amounts relative to these fees as management did not believe it probable that we would be required to pay the fees due to its belief that the term loan credit agreement would be refinanced prior to June 30, 2008.
On October 19, 2007, the parties to the credit agreement also entered into a letter agreement pursuant to which we agreed, at our election and as compensation for the waiver and amendment and assignment agreements, (i) to issue warrants on or before June 30, 2008 to purchase up to 750,000 shares of our common stock at an exercise price of $3.00 per share with a term through December 31, 2011 or (ii) make a cash payment on or before October 17, 2008 in an amount equal to the Black-Scholes value of a warrant, exercisable on or before December 31, 2011, for up to 750,000 shares of our common stock at an exercise price of $3.00 per share, obtained using the “OV” function on Bloomberg Financial Markets and reflecting the calculation assumptions set forth in the lender fee letter, to Steelhead Offshore Capital, LP, Big Bend 38 Investments L.P., and J-K Navigator Fund, L.P. We elected to issue the refinance fee warrant pursuant to the lender fee letter and, on December 31, 2007, entered into a warrant agreement with the parties to the letter agreement. The shares issuable upon exercise of these warrants have registration rights similar to those provided in the Registration Rights Agreement entered into in connection with the October 19, 2007 equity financing (see Note 11, Stockholders’ (Deficit) Equity). Legal expenses totaling approximately $323,000 were expensed as incurred and the value of the warrant was capitalized as deferred financing fees to be amortized over the remaining life of the loan using the effective interest method.
On November 16, 2007, the lenders party to the credit agreement entered into a waiver under which the EBITDA financial covenant was waived for the fiscal quarters ending March 31, 2008 and June 30, 2008.
In March and April 2008, we repaid the $10 million credit agreement with a portion of the proceeds from the sale of our Straight Creek properties, and terminated this agreement.
10.5% Senior Secured Notes Due 2010
On December 29, 2005, we issued $55,000,000 in aggregate principal amount of 10.5% Senior Secured Notes due 2010 (the “10.5% Notes due 2010”) and 55,000 warrants to purchase a total of 1,732,632 shares of our common stock. The 10.5% Notes due 2010 and warrants were sold in units consisting of one $1,000 principal amount note and one warrant, which entitled the holder to purchase 31.5024 shares of our common stock at an exercise price of $8.50 per share, subject to adjustment. The warrants are subject to mandatory conversion if the price of our common stock remains above $12.75 for more than twenty days out of a thirty-day period. The units were sold in a private placement exempt from the registration requirements under the Securities Act of 1933, as amended (the “Securities Act”). The 10.5% Notes due 2010 are fully and unconditionally guaranteed by our wholly-owned subsidiaries, National Coal Corporation, NC Railroad, Inc. and NC Transportation, Inc. and were offered and sold within the United States only to qualified institutional buyers in reliance on Rule 144A under the Securities Act.
The 10.5% Notes due 2010 were issued pursuant to an indenture with Wells Fargo Bank National Association, as trustee. Interest on the 10.5% Notes due 2010 accrues from the date of issuance or the most recent interest payment date, and is payable in cash semi-annually in arrears on June 15th and September 15th of each year, commencing on June 15, 2006. The warrants are exercisable on or after December 29, 2006 and the warrants will expire on December 15, 2010. All of the securities in this offering were initially purchased by the underwriter.
The 10.5% Notes due 2010 and the related guarantees are secured by a lien on substantially all of our and the guarantors’ property and assets, including a pledge of 100% of the capital stock or other equity interests of our domestic subsidiaries. The 10.5% Notes due 2010 will mature on December 15, 2010. The 10.5% Notes due 2010 were subordinated to the $10 million Term Loan Credit Facility with Guggenheim Corporate Funding, LLC, which held a first priority secured lien senior to the 10.5% Notes due 2010, and was senior to our existing and future subordinated debt The Term Loan Credit Facility with Guggenheim was fully repaid with proceeds from the sale of Straight Creek in March and April of 2008.
The 10.5% Notes due 2010 are redeemable, at our option, in whole or part, in each case at the redemption prices described in the table below. All redemptions prices are in addition to any accrued and unpaid interest to the date of the redemption.
The indenture governing the 10.5% Notes due 2010, among other things and subject to certain exceptions, limits our ability and the ability of our subsidiaries to:
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incur or guarantee additional indebtedness or issue preferred stock;
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pay dividends or distributions on, or redeem or repurchase, capital stock;
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make investments;
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issue or sell capital stock of restricted subsidiaries;
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engage in transactions with affiliates;
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grant or assume liens; or
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consolidate, merge or transfer all or substantially all of our assets.
Our failure to make required payments of interest and principal and to comply with other covenants may result in the acceleration of the principal of the 10.5% Notes due 2010.
We agreed, pursuant to a registration rights agreement with the initial purchaser, to use our commercially reasonable efforts to (a) register with the SEC a new issue of notes having substantially identical terms as the 10.5% Notes due 2010 in order to exchange freely tradable notes for the 10.5% Notes due 2010, and (b) file a shelf registration statement with the SEC covering the resale of the warrants and shares of our common stock issuable upon exercise of the warrants, and to use our commercially reasonable efforts to cause that resale registration statement to be declared effective within 240 days after the sale date. We filed registration statements subject to our obligations under the registration rights agreement on May 15, 2006. Both registration statements were declared effective on July 28, 2006, and we issued $51.0 million in principal amount of freely tradable notes in exchange for the same principal amount of 10.5% Notes due 2010.
We immediately used approximately $22.1 million of the proceeds of the 10.5% Notes due 2010 offering to repay existing indebtedness. During the year ended December 31, 2007, we used approximately $2.0 million to purchase a forty-two mile rail line in Tennessee, approximately $8.3 million as collateral to support reclamation bonds, and $19.7 million to purchase other equipment, refurbish a preparation plant and rail load-out, and to use as working capital.
On February 22, 2008, we entered into a letter agreement with Neuberger Berman, LLC, in its capacity as the representative of certain of its clients who hold 10.5% Notes due 2010. Pursuant to the exchange agreement we agreed to exchange a minimum of $2.0 million and a maximum of $10.0 million in principal amount of the holders’ notes for shares of our common stock. The number of shares of common stock to be delivered to the holders upon an exchange would equal (x) the principal amount of each respective Note exchanged multiplied by 0.82, plus the accrued but unpaid interest, divided by (y) $4.85, which price represents a 5.0% discount to the closing price our common stock on February 19, 2008, the day we reached agreement with the holders of the notes. On February 28, 2008, the representative elected to exchange notes in the aggregate principal amount of $3 million plus accrued interest thereon of $63,875, for 520,387 shares of our common stock, and the exchange agreement thereafter expired on March 22, 2008.
On May 20, 2008, we entered into a letter agreement with Neuberger Berman, LLC, in its capacity as the representative of certain of its clients who hold 10.5% Notes due 2010. Pursuant to the exchange agreement we agreed to exchange a minimum of $2.0 million and a maximum of $10.0 million in principal amount of the holders’ notes for shares of our common stock. The number of shares of common stock to be delivered to the holders upon an exchange would equal (x) the principal amount of each respective Note exchanged multiplied by 0.90, plus the accrued but unpaid interest, divided by (y) $6.81. On May 28, 2008, the representative elected to exchange notes in the aggregate principal amount of $2 million plus accrued interest thereon of $95,083 for 278,279 shares of our common stock. This portion of the exchange settled on May 28, 2008.
On June 3, 2008, we amended the agreement to, among other things, (i) extend the final settlement date from June 3, 2008 to June 9, 2008, and (ii) provide that for any settlements that occur after June 1, 2008, only the principal amount of the Notes would be exchanged for common stock and all accrued interest thereon would be paid in cash on the next scheduled interest date.
On June 2, 2008, the representative elected to exchange notes in the aggregate principal amount of $3 million for 396,476 shares of our common stock. This portion of the exchange settled on June 4, 2008.
On June 6, 2008, the representative elected to exchange notes in the aggregate principal amount of $5 million for 660,793 shares of our common stock. This portion of the exchange settled on June 9, 2008.
Installment Purchase Obligations and Equipment Notes
In November and December 2008, we entered into new equipment notes pursuant to which we purchased vehicles with an aggregate principal value of $127,849. The notes require payments over 36 months with fixed interest rates ranging from of 8.19% to 8.69%. The obligations under the notes are secured by the vehicles purchased.
In August 2008, we entered into new equipment notes pursuant to which we purchased vehicles with an aggregate principal value of $129,104. The notes require payments over 36 months with a fixed interest rate of 6.99%. The obligations under the notes are secured by the vehicles purchased.
In June 2008, we acquired $1,175,000 of used equipment in exchange for $100,000 cash, a $244,000 note payable and the assumption of $831,000 in equipment loans. The $244,000 note payable requires repayment in one year at 8% interest. The assumed equipment loans require payments over 55 months at fixed interest rates ranging from 7.45% to 8.0%. The obligations under the notes are secured by the purchased equipment.
In April 2008, we entered into a new installment sales contract and new equipment notes with equipment manufacturers pursuant to which we acquired equipment with an aggregate principal value of approximately $1,179,451 and $681,040, respectively. The installment sales contract requires payments over 36 months at a fixed interest rate of 6.25% and the equipment notes require payments over 36 months with a fixed interest rate of 4.75%. The obligations are secured by the equipment purchased.
In February, March and June 2008, we entered into new equipment notes with a bank and an equipment manufacturer pursuant to which we purchased vehicles with an aggregate principal value of approximately $103,000. These equipment notes require payments over 36 months at fixed interest rates of 7.75%. The obligations under the equipment notes are secured by the vehicles purchased.
In January and February 2007, we entered into new installment sale contracts with an equipment manufacturer pursuant to which we refinanced equipment with an aggregate principal value of approximately $719,000 formerly acquired under various capital leases. These installment sale contracts require payments over 36 months at fixed interest rates ranging from 5.29% to 8.75%. The obligations under the installment sale contracts are secured by the equipment purchased.
In August 2007, we entered into new installment sale contracts with equipment manufacturers pursuant to which we acquired equipment with an aggregate principal value of approximately $4,889,000. These installment sale contracts require payments over 36 to 60 months at fixed interest rates ranging from 5.97% to 7.99%. The obligations under the installment sale contracts are secured by the equipment purchased.
Approximately $2.6 million of equipment related debt was assumed by Xinergy Corp. on March 31, 2008, as a result of the sale of our Straight Creek, Kentucky properties.
Cash Flows
We currently satisfy our working capital requirements primarily through cash flows generated from operations and sales of debt and equity securities. For the twelve months ended December 31, 2008, we had a net decrease in cash of approximately $5.2 million. Cash flows from operating, financing and investing activities for the twelve months ended December 31, 2008, 2007, and 2006 are summarized in the following table:
Operating Activities
The net cash used in operating activities of approximately $4.5 million during the year ended December 31, 2008 compared with prior year cash used in operations of $8.1 million was primarily attributable to the current period activity including a full year of operating results for National Coal of Alabama while only being offset by three months of operating losses associated with the Straight Creek mining operations. The comparable period in the prior year includes Straight Creek operating losses and included National Coal of Alabama operations for only three months. However, in the first quarter of 2008, our dragline equipment utilized in our L. Massey surface mine in Alabama suffered a major mechanical failure. The equipment was repaired and was back in full production on July 29, 2008. This breakdown resulted in estimated lost production of 140,000 tons and lost revenues of $9.5 million during the year ended December 31, 2008, respectively.
The net cash used in operating activities of approximately $8.1 million during the year ended December 31, 2007 compared to $3.8 million for the year ended December 31, 2006 was primarily attributable to a net loss over 2006 of $2.3 million along with the acquisition of Mann Steel Products, Inc. on October 19, 2007 net of gains on the sale of idle assets including certain of our mineral properties at Pine Mountain, Kentucky and an increase in inventory, accounts receivable and depreciation, depletion, amortization and accretion. We expect to have positive cash flows from operations in 2009, which is important for our ability to continue as a going concern.
Net cash used in operating activities of approximately $3.8 million during the year ended December 31, 2006 was primarily the result of an increase in net loss, net of depreciation, depletion, amortization and accretion and non-cash stock option expense, of $9.9 million. The increase was primarily due to lower contract prices, increased purchases of coal due in part to the highwall miner damage during the year, and the termination of a financially favorable agreement with a subcontractor for the management of our Kentucky properties, partially offset by increased non-cash stock option expenses of $1.4 million over prior year due to the adoption of SFAS123 (R) and the accelerated vesting of certain executive options. Offsetting the overall decrease in cash flow from operations is a greater increase in accounts payable of $3.6 million primarily attributable to the refurbishment of our Baldwin preparation plant and load-out facility which took place in 2006 and increased interest due to higher debt balances. These and other expansion activities have also resulted in a greater increase in inventory of $1.7 million in current year and $1.1 million of asset retirement obligation settlements, both of which decreased cash from operations.
Approximately $1.93 million of expense related to the March 2006 damage to our highwall miner was reflected as cash used in operations in the first and second quarters of 2006 and was offset by an insurance settlement of approximately $1.87 million received in September 2007.
Investing Activities
The change in cash provided by investing activities of $3.9 million for the year ended December 31, 2008 compared to cash used in investing activities of $70.8 million for the year ended December 31, 2007 was primarily attributable to: (i) the acquisition of Mann Steel Products, Inc. on October 19, 2007 for $58.7 million and a $10.2 million investment in reclamation bonds and other restricted cash during 2007 offset by (ii) the sale of our Straight Creek, Kentucky properties in March 2008 for $10.6 million and (iii) the release of $7.0 million of reclamation bonds associated with the Straight Creek mining operations during 2008.
Cash used in investing activities increased $44.4 million in the year ended December 31, 2007 over 2006 to approximately $70.8 million primarily as the result of the acquisition of Mann Steel Products, Inc. on October 19, 2007 for approximately $58.3 million and $10.2 million investment in reclamation bonds and other restricted cash necessary to expand our operations net of the reduced capital expenditures necessary as a result of significant capital improvements made in 2006 and 2005.
Cash used in investing activities for the twelve months ended December 31, 2006 of $26.4 million was primarily related to net capital expenditures of approximately $16.3 million including the acquisition of a forty-two mile rail line in Tennessee and renovations to a processing facility in Tennessee along with an increase in cash collateral supporting reclamation bonds of approximately $9.9 million.
Financing Activities
The change in net cash used in financing activities of $4.6 million during the year ended December 31, 2008 compared to the net cash provided by financing activities of $86.6 million for the year ended December 31, 2007 was primarily due to: (i) the proceeds we received from our 12% senior secured notes due 2012 during 2007 of $60.0 million to purchase Mann Steel Products Inc. and (ii) proceeds from the issuance of common stock of 34.1 million during 2007 compared to $10.9 million raised in equity financings for the year ended December 31, 2008. During 2008, cash was used to repay the Term Loan Credit Facility and notes and equipment related financing totaling approximately $15.8 million compared to $6.3 million in 2007.
Cash flows provided by financing activities were $86.6 million for the year ended December 31, 2007, an increase of $79.6 million over 2006. Proceeds from the issuance of 9,066,968 shares of our common stock, including 3,866,968 shares issued in conjunction with our acquisition of Mann Steel Products, Inc. on October 19, 2007, resulted in cash flows of $34.1 million. An additional $60.0 million was raised from the October 19, 2007 issuance of our 12.0% Notes due 2012 in conjunction with our acquisition of Mann Steel Products and $2.0 in borrowings for working capital were obtained from our term loan credit facility. Approximately $1.70 million was paid to the holders of our Series A cumulative convertible preferred stock to induce them to convert their shares to common. The holders subsequently used approximately $1.65 million of the inducement paid to purchase 558,701 additional shares of our common stock.
Off-Balance Sheet Arrangements
At December 31, 2008, 2007, and 2006, we did not have any relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structured finance, variable interest or special purpose entities, except as noted below, which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. As such, we are not exposed to any financing, liquidity, market or credit risk that could arise if we had engaged in such relationships.
At December 31, 2008 and December 31, 2007, we, through our subsidiary, National Coal of Alabama, Inc., held an investment totaling $331,889 and $114,823, respectively, representing a 49% interest in Powhatan Dock, LLC (“Powhatan”) which operates a barge load-out in Alabama. We use the equity method to account for the joint venture investment in Powhatan, which was acquired during the fourth quarter of 2007. Powhatan recorded revenues of $4,117,625 and net income of $943,012 during the year ended December 31, 2008.
Contractual Obligations
The following summarizes our contractual obligations at December 31, 2008 and the effects such obligations are expected to have on liquidity and cash flow in future periods:
We rent mining equipment pursuant to operating lease agreements, and made lease payments totaling approximately $2,337,537 during the year ended December 31, 2008.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
Market Risk is the risk of loss arising from adverse changes in market rates and prices, such as interest rates, foreign currency exchange rates and commodity prices.
Interest Rate Risks
Our interest expense is sensitive to changes in the general level of interest rates in the U.S. At December 31, 2008, we had $107.1 million aggregate principal amount of debt under fixed rate instruments and no debt under variable rate instruments. At December 31, 2007, we had $129.8 million aggregate principal amount of debt under fixed rate instruments and no debt under variable rate instruments.
Commodity Risks
We are subject to commodity price risk based on the fluctuating market price of coal. We manage this risk through securing long-term coal supply agreements rather than through use of derivative instruments. In the future, as existing long-term contracts expire or become subject to repricing, our coal sales will be made at then-current market prices. As a result, our revenues and net income will be significantly affected by fluctuations in the price of coal.
Coal prices are influenced by a number of factors and vary dramatically by region. The two principal components of the delivered price of coal are the price of coal at the mine, which is influenced by coal quality, and the cost of transporting coal from the mine to the point of use. Electricity generators purchase coal on the basis of its delivered cost per million Btu. As macroeconomic factors affect these commodity prices, the price of coal will similarly be impacted.
The cost of operating a mine is influenced by geological characteristics such as seam thickness, overburden ratios and depth of underground reserves. It is generally cheaper to mine coal seams that are thick and located close to the surface than to mine thin underground seams. Typically, coal mining operations will begin at the part of the coal seam that is easiest and most economical to mine. As the seam is mined, it becomes more difficult and expensive to mine because the seam either becomes thinner or extends more deeply into the earth, requiring removal of more overburden. Underground mining is generally more expensive than surface mining as a result of high capital costs including costs for modern mining equipment and construction of extensive ventilation systems and higher labor costs, including costs for labor benefits and health care.
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. Coal used for domestic consumption is generally sold freight on board at a loading point, and the purchaser normally pays the transportation costs. Export coal is usually sold at an export terminal, and the seller is responsible for shipment to the export coal loading facility while the purchaser pays the ocean freight. Most electric power generators arrange long-term shipping contracts with rail or barge companies to assure stable delivery costs. Transportation cost can be a large component of the purchaser’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. 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. Railroads typically handle approximately 60% of U.S. coal production, with CSX and Norfolk Southern the dominant carriers in the eastern United States.
Some products used in mining activities, such as diesel fuel, are subject to price volatility. We use short-term fuel contracts to manage the volatility related to this exposure.
Foreign Currency
All of our transactions are denominated in U.S. dollars, and as a result, we do not have material exposure to currency exchange rate risk.
Item 8.
Item 8. Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of
National Coal Corp.
We have audited the consolidated balance sheets of National Coal Corp. (the “Company”) as of December 31, 2008 and 2007 and the related consolidated statements of operations, stockholders’ equity (deficit) and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of National Coal Corp. at December 31, 2008 and 2007, and the consolidated results of its operations and its cash flows for the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 2 to the consolidated financial statements, the Company changed its method of accounting for income tax contingencies in accordance with Financial Accounting Standards Board Interpretation No. 48 on January 1, 2007.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), National Coal Corp.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 30, 2009 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Nashville, Tennessee
March 30, 2009
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders of
National Coal Corp.
We have audited National Coal Corp.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). National Coal Corp.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, National Coal Corp. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of National Coal Corp. as of December 31, 2008 and 2007 and the related consolidated statements of operations, stockholders’ equity (deficit) and cash flows for each of the three years in the period ended December 31, 2008 and our report dated March 30, 2009 expressed an unqualified opinion thereon.
Nashville, Tennessee
March 30, 2009
National Coal Corp.
Consolidated Balance Sheets
See Accompanying Notes to Consolidated Financial Statements.
National Coal Corp.
Consolidated Statements of Operations
See Accompanying Notes to Consolidated Financial Statements.
National Coal Corp.
Condensed Consolidated Statements of Cash Flows
See Accompanying Notes to Consolidated Financial Statements.
National Coal Corp.
Consolidated Statements of Changes in Stockholders’ Equity (Deficit)
See Accompanying Notes to Consolidated Financial Statements.
NATIONAL COAL CORP.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. Business Overview
National Coal Corp. (the “Company”) principally engages in the business of mining high quality bituminous steam coal in East Tennessee, North Alabama and until March 31, 2008, in Southeast Kentucky. Its customers are electric utilities and industrial concerns in the surrounding states.
The Company owns the coal mineral rights to approximately 65,000 acres of land and leases the rights to approximately 17,700 additional acres excluding the Southeast Kentucky properties. As of December 31, 2008, the Company’s mining complexes included three active and two inactive underground mines, one underground mine in the development stage, one inactive and six active surface mines, and one highwall mine. In addition, the Company has two preparation plants and two unit train loading facilities in Tennessee served by the Norfolk Southern (“NS”) railroad. The Company is a minority joint venture partner in a barge loading facility on the Warrior River in North Alabama. The Company holds seven permits that allow them to open new or re-open existing mines close to their current operations. As of December 31, 2008, the Company controlled approximately 40.8 million estimated recoverable tons of coal reserves as defined by the SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted at the time of the reserve determination.
At December 31, 2008, the Company had cash and cash equivalents of approximately $4.6 million and negative working capital of approximately $6.0 million. Cash flows used in operations were $4.8 million, $8.1 million and $3.8 million for the years ended December 31, 2008, 2007 and 2006, respectively. At December 31, 2008, the Company had stockholders’ equity of $5.5 million and incurred net losses of $34.9 million (excluding preferred stock dividends) for the year then ended. Management expects that the Company may continue to incur net losses in the future, which would decrease stockholders’ equity and could lead to an eventual stockholders’ deficit.
Management believes that the Company has sufficient resources to fund its operations through 2009. However, this belief is predicated on certain assumptions as to: (i) sales volumes and related pricing, (ii) production levels, (iii) the availability of coal to be purchased at a reasonable price; (iv) budgeted capital expenditures; and (v) cost per ton level decreases at existing mines and newly opened mines. Significant deviation from any one of these assumptions could have a material adverse effect on the Company’s operating cash flows and the ability for the Company’s wholly-owned subsidiary National Coal of Alabama, Inc. (“NCA”) to meet certain debt covenants. Management believes that NCA will be in compliance with its debt covenants during 2009. However, there can be no assurances that a debt covenant violation will not occur, or that the Company will have sufficient cash to satisfy its obligations.
The agreements governing the Company’s outstanding senior debt impose a number of restrictions, the most significant of which is the inability to loan funds or infuse capital between NCA and National Coal Corp. Additionally, the terms of the Company’s credit facilities contain financial and other covenants that create limitations on its ability to affect acquisitions or dispositions, incur additional debt and may require the Company to maintain various financial ratios and comply with various other financial covenants. In the second, third and fourth quarters of 2008, NCA failed to meet certain financial covenants required under its 12% Notes due 2012. In each instance, waivers of covenant failures and modifications of future financial covenants were obtained. With respect to the second and fourth quarter waivers only, NCA was charged penalties of $300,000 each quarter for covenant waiver and modification. NCA’s ability to comply with these restrictions may be affected by events beyond its control and, as a result, it may be unable to comply with these restrictions. A failure to comply with these restrictions could adversely affect the Company’s ability to borrow under a new credit facility or result in an event of default under these agreements. In the event of a default, NCA’s lenders could terminate their commitments to them and declare all amounts borrowed, together with accrued interest and fees, immediately due and payable. If this were to occur, NCA might not be able to pay these amounts, or could be forced to seek an amendment to its financing arrangements which could make the terms of these arrangements more onerous. As of December 31, 2008, neither the Company nor NCA have a revolving credit agreement for working capital in place.
The Company relies primarily on its ability to generate cash from operations to service its debt. If it does not generate sufficient cash flows to meet its debt service, the Company may need to seek additional financing, the availability of which is uncertain given the current state of credit markets. If it is unable to obtain financing on terms that are acceptable to them amidst the tightening credit market, the Company could be forced to raise equity financing or sell assets to make up for any shortfall in its payment obligations under unfavorable circumstances. The 10.5% Notes due 2010 and the 12% Notes due 2012 limit its ability to sell assets and also restrict the use of the proceeds from any such sale. However, these debt facilities do allow asset sales if the funds generated from such sales are used to pay outstanding debt and prepayment costs associated with these debt obligations. Even if asset sales are permitted, the Company may not be able to sell assets in a timely manner or for sufficient amounts to enable them to meet its debt obligations.
The Company does not believe that it will be able to generate from operations the amount of cash necessary to pay in December 2010 the principal amounts of its 10.5% Notes due 2010. The outstanding principal balance of this indebtedness at December 31, 2008 was $42,000,000. The Company intends to refinance this indebtedness prior to its maturity by incurring additional debt, the availability of which is uncertain given the current state of credit markets. If the Company is unable to refinance this indebtedness, the Company would be required to repay this indebtedness from other sources, including cash raised from equity financings or sales of assets, which may occur under unfavorable circumstances.
During the year ended December 31, 2008, the Company generated total revenues of $132.6 million and sold approximately 2.0 million tons of coal. The Company’s revenues are derived primarily from the sale of coal to electric utility companies and industrial customers in the Southeastern United States pursuant to long-term contracts or open purchase order arrangements with long-time customers. Long-term contracts as are customary in the industry, are those with a contract duration of one year or more. The Company’s largest customers were Georgia Power, Alabama Power, and Solutia, Inc., representing approximately 34%, 21% and 14% of its revenues, respectively.
During 2008, the Company successfully renegotiated several of its existing coal supply agreements resulting in an increased selling price per ton and additional revenues from those contracts. The weighted average selling price per ton is $75.28, $77.40, and $79.43 on 2.1 million, 1.0 million, and 0.35 million tons contracted for 2009, 2010, and 2011, respectively. The Company typically sells its coal for a specified per ton amount and at a negotiated price pursuant to both short-term contracts and contracts of twelve months or greater. For the year ended December 31, 2008, 88% of sales were pursuant to contracts of twelve months or greater. Price adjustment, “price reopener” and other similar provisions in long-term supply agreements may reduce the protection from short-term coal price volatility traditionally provided by such contracts. Any adjustment or renegotiation leading to a significantly lower contract price would result in decreased revenues and lower gross margins, which could have a material adverse effect on the Company’s operating cash flows. Additionally, the Company’s customers may have the ability to delay the timing of their purchases, which could negatively impact operating cash flows. Finally, coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by the Company or its customers during the duration of specified events beyond the control of the affected party.
The Company has not yet priced a portion of the coal it has the capability of producing over the next several years in order to take advantage of possible future market demand or to realize possible long term opportunities with certain users of the high quality coal contained in its reserve base. At December 31, 2008, the Company’s un-priced and uncommitted future production was approximately 0.2 million to 0.3 million tons in 2009, 1.1 million to 1.5 million tons in 2010, and 2.5 million tons in 2011. For 2009, the Company has assumed it will be able to achieve a minimum spot rate on unpriced tons. If the Company is unable to obtain this rate, it would reduce production.
The Company assumes it will meet its contract commitments through a combination of produced tons and purchased coal. The Company’s ability to produce tons can be negatively impacted by weather, labor shortages or equipment breakdowns. Additionally, geological and mining conditions may not be fully identified by available exploration data or may differ from experience in current operations. During 2008, the Company experienced severe increases in diesel fuel and costs associated with all petroleum related products and also encountered additional regulatory examination, as did most of its competitors, that weakened productivity. The Company experienced equipment failure in 2008 which negatively impacted the tons of coal produced and therefore sold. Additionally, coal for purchase may not be available, or available only at unfavorable prices. The occurrence of such events can adversely affect production, the cost of sales or both, and could have a material adverse effect on the Company’s operating cash flows.
The Company invested approximately $24.1 million in equipment and mine development during the year ended December 31, 2008 including $6.9 million purchased through equipment financing arrangements. Management has estimated capital expenditures for 2009 to be $6.3 million to expand operations and approximately $1.8 million to maintain existing assets. The Company expects to finance $6.3 million of these capital expenditures in 2009. If financing is unable to be obtained, this could negatively impact planned production levels. During the first quarter of 2008, the Company’s dragline equipment utilized in its L. Massey surface mine in Alabama suffered a major mechanical failure. The equipment has since been repaired and was back in production during the third quarter of 2008. This breakdown resulted in estimated lost production of 140,000 tons and lost revenues of $9.5 million during the year ended December 31, 2008. In prior years, the Company also experienced the unanticipated loss of the use of a highwall miner, which resulted in lost production and lost revenues. The Company may experience similar mechanical failures in the future, which could have a material adverse effect on its operating cash flows.
2. Summary of Significant Accounting Policies
Basis of Presentation
The accompanying consolidated financial statements include the accounts of National Coal Corp. and those of its two wholly-owned operating subsidiaries, National Coal Corporation and NCC Corp. and their respective wholly-owned subsidiaries, NC Railroad, Inc. and National Coal of Alabama, Inc. NCC Corp. was created and National Coal of Alabama Inc., formerly Mann Steel Products, Inc., was acquired on October 19, 2007 and thus, only operations and cash flows for the period from October 20 through December 31, 2007 are reflected in the consolidated financial statements for the year ended December 31, 2007. All intercompany transactions and balances have been eliminated in consolidation. Investments in business entities in which National Coal Corp. and its subsidiaries do not have control, but have the ability to exercise significant influence over the operating and financial policies, are accounted for under the equity method.
Use of Estimates
The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates, judgments, and assumptions that affect the reported amounts and related disclosures of assets, liabilities, revenues, and expenses at the date of the financial statements and for the periods then ended. On an on-going basis, management evaluates the estimates used, including those related to workers’ compensation, reclamation and mine closure obligations, coal reserve values, income taxes, and contingencies. Estimates are inherent in the disclosure of economically recoverable reserves and in the information developed by management to support its ability to remain in compliance with debt covenant and to have sufficient cash to remain a going concern. Estimates are based on historical experience, actuarial estimates, current conditions, and various other assumptions that management believes to be reasonable under the circumstances. Actual results may differ from these estimates.
Cash and Cash Equivalents
Cash and cash equivalents are stated at cost. Cash equivalents consist of highly liquid investments with maturities of three months or less when acquired.
The Company maintains cash or investment accounts at various banks. The accounts are insured by the Federal Deposit Insurance Corporation up to $250,000 per legal ownership. At December 31, 2008, the Company had $3.8 million of non restricted funds and $26.5 million of restricted funds deposited with financial institutions and regulatory agencies in excess of this insurance limit.
Accounts Receivable
Trade accounts receivable are recorded at the invoiced amount and do not bear interest. Customers are primarily utility companies. Balances are stated net of an allowance for doubtful accounts, which was $430,000 and $0 at December 31, 2008 and 2007, respectively. Bad debts written off were approximately $253,000, $0 and $0, net of recoveries of approximately $115,000, $0 and $0 in 2008, 2007 and 2006, respectively.
Inventory
Inventory includes mined coal, purchased coal and tires. Mined coal is classified as inventory at the point it is extracted, and is valued at the lower of average cost or net realizable value. At December 31, 2008 and 2007, the Company reduced the carrying value of its inventories by $1,255,157 and $287,295, respectively, to state mined coal inventories at net realizable value. Mined coal inventory costs include labor, fuel, equipment costs, and operating overhead. Purchased coal inventory is valued at the lower of cost or net realizable value. Tires are classified as inventory when purchased.
Property, Plant, Equipment and Mine Development
Property and equipment are stated at cost. Maintenance and repairs that do not improve efficiency or extend economic life are expensed as incurred. Plant and equipment are depreciated using the straight-line method over the estimated useful lives of assets which generally range from seven to thirty years for building and plant and one to seven years for equipment. On sale or retirement, asset cost and related accumulated depreciation are removed from the accounts and any related gain or loss is reflected in income.
Leasing is used for certain capital additions when considered cost effective relative to other capital sources, and is classified as either capital or operating as appropriate. Leased equipment meeting the capital lease criteria of Statement of Financial Accounting Standards (SFAS) 13, Accounting for Leases are capitalized and the present value of the related lease minimum payments are recorded as a corresponding asset and liability. Amortization of capitalized leased assets is computed using the straight-line method over the shorter of the estimated useful life or the initial lease term.
Mineral rights represent tangible assets that are recorded at fair value when acquired, including amounts associated with any value beyond proven and probable reserves. Mine development costs are recorded at cost as incurred. The Company’s coal reserves are controlled either through direct ownership or through leasing arrangements which generally last until the recoverable reserves are depleted. Depletion of reserves and amortization of mine development costs is computed using the units-of-production method over the estimated proven and probable recoverable tons.
The Company reviews its long-lived assets for impairment when events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. If impairment indicators are present and the future undiscounted cash flows are less than the carrying value of the assets, the carrying values are reduced to the estimated fair value.
Deferred Financing Costs
Deferred financing costs represent capitalized expenses associated with the issuance of debt. Deferred financing costs are amortized by the interest method over the life of the associated debt.
Restricted Cash
Restricted cash includes accrued interest and consists principally of certificates of deposit and money market accounts securing letters of credit and surety bonds in favor of the various federal and state mining commissions. The current portion of restricted cash includes (i) short-term deposits for which statutory restrictions will be released within one year and (ii) an estimate of performance bond amounts associated with those permits for which the reclamation work has been completed and the release has been requested from the appropriate mining commission prior to the reporting date.
Investments Accounted For Using the Equity Method
In November 2007, National Coal of Alabama acquired a 49% interest in Powhatan Dock, LLC which operates a barge load-out facility in Alabama. The Company accounts for its investment using the equity method. During 2008 and 2007, the Company recorded $462,076 and $(41,977) of equity method gains (losses) associated with this investment and, in 2008, received a distribution of $245,000. Powhatan Dock, LLC recorded revenues of $4,117,625 and $8,656 and net income (loss) of $943,012 and $(85,668) during the years ended December 31, 2008 and 2007, respectively. The Company paid barge loading fees of $847,772 to Powhatan Dock, LLC during 2008.
Prepaid Mining Royalties
Certain coal leases require minimum or advance payments which are deferred and charged to cost of sales as coal is extracted and sold. The Company had prepaid royalties of approximately $578,000 and $935,000 at December 31, 2008, and 2007, respectively, included in other non-current assets in the accompanying balance sheets.
Reclamation and Asset Retirement Obligations
The Surface Mining Control and Reclamation Act of 1977 and similar state statutes require mine properties to be restored in accordance with specified standards. Statement of Financial Accounting Standards No. 143 (“SFAS No. 143”) requires recognition of an asset retirement obligation (“ARO”) for eventual reclamation of disturbed acreage remaining after mining has been completed. The Company records its reclamation obligations on a permit-by-permit basis using requirements as determined by the Office of Surface Mining of the U.S. Department of the Interior (“OSM”). The liability is calculated based upon the reclamation activities remaining after coal removal ceases, assuming that reclamation activities have been contemporaneous within state and federal guidelines during mining. A liability is recorded for the estimated future cost that a third party would incur to perform the required reclamation and mine closure discounted at the Company’s credit-adjusted risk-free rate. A corresponding increase in the asset carrying value of mineral rights is also recorded. The ARO asset is amortized on the units-of-production method over the proven and probable reserves associated with that permit, and the ARO liability is accreted to the expected reclamation date at the Company’s credit-adjusted risk-free rate. These expenses are included in depreciation, depletion, amortization, and accretion in the operating expenses section of the income statement.
Stock-based Compensation
The Company’s 2004 Option Plan (the “Plan”) was authorized by the Board of Directors of the Company in March 2004, and amended in January 2005. Under the terms of the Plan, stock options may be granted to officers, directors, employees, and others. At December 31, 2008, 4,450,000 shares of common stock were authorized for issuance under the Plan. Shares subject to awards that expire unexercised or are otherwise terminated, again become available for awards. Upon exercise, stock is issued from unissued or treasury shares. The grant price of an option under the Plan generally may not be less than the fair market value of the common stock subject to such option on the date of grant. Options have a maximum life of ten years and generally vest 25% per year over a four year period. Currently, all stock options issued under the plan are non-statutory.
Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123, Share-Based Payment (“SFAS 123(R)”) using the modified-prospective transition method. SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized as compensation expense in the consolidated financial statements based on their fair values. Under the modified-prospective transition method, the Company recognizes compensation expense for the unvested portion of all share-based payments granted on or prior to December 31, 2005 over the remaining service period based on the grant date fair value estimated in accordance with SFAS 123(R) and recognizes compensation cost for all share-based payments granted on or subsequent to January 1, 2006 over the service period based on grant date fair value estimated in accordance with SFAS 123(R).
Workers’ Compensation
In Tennessee, the Company provides for income replacement and medical treatment for work related injury and occupational disease resulting from coal workers’ pneumoconiosis (Black Lung Disease), as required by federal and state law, through insurance policies with high deductibles. In Alabama, the Company provides “total cost” insurance policies which have minimal deductibles. Loss funding provisions for deductibles are based on determinations by independent actuaries or claims administrators.
Revenue Recognition
The Company recognizes revenue when title or risk of loss passes to the common carrier or customer. This generally occurs when coal is loaded onto trains, barges or trucks at one of our loading facilities or at third party facilities. In most cases, the Company negotiates a specific sales contract with each customer, which specifies a fixed price per ton, premiums and penalties for quality variances, a delivery schedule, and payment terms. Contracts range in duration from one to three years. In 2008, the Company entered into a supply contract with a broker and received advance payment for product to be delivered in January 2009. This payment was recorded as deferred revenue in the accompanying balance sheet.
Revenue is also earned from contract mining services, from tippling fees charged other coal producers to use the Company’s loading facilities and from royalties based on coal mined by lessees.
Freight Revenue and Costs
Shipping and handling costs paid to third-party carriers and invoiced to coal customers are included in coal sales and cost of sales, respectively.
Income Taxes
The Company recognizes deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases in accordance with FASB Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes. A valuation allowance is provided when it is
more likely than not that some portion or all of a deferred tax asset will not be realized. The ultimate realization of deferred tax assets depends on the generation of future taxable income during the period in which related temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in this assessment. Deferred tax assets and liabilities are measured using the enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date of such change.
Comprehensive Loss
The Company’s comprehensive losses as defined by SFAS No. 130, Reporting Comprehensive Income, are the same as the net losses reported.
Reclassifications
Certain prior year amounts have been reclassified to conform to the current year presentation.
Recent Accounting Pronouncements
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, Fair Value Measurements (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. SFAS 157 applies under other accounting pronouncements that require or permit fair value measurements. SFAS 157 is effective prospectively for fiscal years beginning after November 15, 2007 and interim periods within that fiscal year. In February 2008, the FASB issued FASB Staff Position FAS 157-2, Effective Date of FASB Statement No. 157, referred to as FSP 157-2. FSP 157-2 delays the effective date of SFAS 157 for one year for all nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis. The Company adopted SFAS 157 effective January 1, 2008. Adoption has not had a material impact on the Company’s financial position or results of operations.
In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Liabilities - Including an amendment of FASB Statement No. 115 (“SFAS 159”) SFAS 159 permits entities to choose to measure many financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The Company adopted SFAS 159 effective January 1, 2008. Adoption has not had a material impact on the Company’s financial position or results of operations.
In December 2007, the FASB issued Statement of Financial Accounting Standards No. 141R, Business Combinations (“SFAS 141R”) which became effective December 15, 2008. SFAS 141R establishes principles and requirements for determining how an enterprise recognizes and measures the fair value of certain assets and liabilities acquired in a business combination, including non-controlling interests, contingent consideration, and certain acquired contingencies. SFAS 141R also requires acquisition-related transaction expenses and restructuring costs be expensed as incurred rather than capitalized as a component of the business combination. SFAS 141R will have an impact on the accounting for any businesses acquired after the effective date of this pronouncement.
In December 2007, the FASB issued Statement of Financial Accounting Standards No. 160, Non-controlling Interests in Consolidated Financial Statements-An Amendment of ARB No. 51 (“SFAS 160”).
SFAS 160 establishes accounting and reporting standards for the non-controlling interest in a subsidiary (previously referred to as minority interests). SFAS 160 would have an impact on the presentation and disclosure of the non-controlling interests of any non wholly-owned businesses acquired in the future. SFAS 160 will be effective for fiscal years beginning after December 15, 2008; earlier adoption is prohibited. The Company does not expect the adoption of SFAS 160 to have a material impact on the Company’s financial position or results of operations.
In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No. 133 (“SFAS 161”) which changes the disclosure requirements for derivative instruments and hedging activities. SFAS 161 requires enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS 133, Accounting for Derivative Instruments and Hedging Activities and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. This SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The Company does not expect adoption of SFAS 161 to have a material impact on the Company’s financial position or results of operations.
In May 2008, the FASB issued Statement of Financial Accounting Standards No. 162, The Hierarchy of Generally Accepted Accounting Principles (“SFAS 162”). SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles in the United States of America. SFAS 162 is effective sixty days following the SEC’s approval of PCAOB amendments to AU Section 411, The Meaning of ‘Present fairly in conformity with generally accepted accounting principles’. The Company does not expect the adoption of SFAS 162 to have a material impact on the Company’s financial position or results of operations.
3. Acquisitions and Divestitures
Mann Steel Acquisition
On October 19, 2007, NCC Corp. acquired all of the outstanding stock of Mann Steel Products, Inc. (“Mann Steel”) for an aggregate purchase price of $55,000,000 less (i) $1,900,000 placed in escrow for payment to certain key employees of Mann Steel (or otherwise returned to sellers), and (ii) $7,406,745 for repayment of certain indebtedness of Mann Steel that existed at the closing date. Simultaneously, the Company completed (i) $60 million in debt private placements with detachable warrants to purchase 250,000 shares of National Coal Corp. common stock at a per share price of $4.00 and (ii) $11.6 million in equity private placements through the issuance of 3,866,968 shares of common stock at a per share price of $3.00 (see Notes 8 and 11). The Company used the proceeds of the private placements to capitalize NCC Corp. which was then used to pay a portion of the purchase price to the sellers of Mann Steel. Mann Steel became a wholly-owned subsidiary of NCC Corp. and changed its name to National Coal of Alabama, Inc. (“NCA”).
On December 19, 2007, the Company paid $3,281,313 to the sellers, pursuant to a working capital adjustment clause contained in the purchase agreement, bringing the total consideration paid to $58,660,706 which includes acquisition costs of $379,393.
The following table summarizes the final purchase price allocation based on the fair values of the assets acquired and liabilities assumed at the date of acquisition:
The allocation of the purchase price to the fair values of the assets acquired and liabilities assumed of Mann Steel resulted in negative goodwill of $6,314,096. In accordance with Statement of Financial Accounting Standards No. 141, Accounting for Business Combinations, the excess goodwill was allocated as a pro rata reduction of the amounts assigned to the assets acquired excluding financial assets, deferred taxes and all other current assets. This resulted in the following allocation of excess goodwill:
The following summarized unaudited consolidated pro forma results of operations, assuming the Mann Steel acquisition occurred on January 1, 2006, are as follows (in $000’s, except for per share amounts):
Straight Creek Divestiture
On March 31, 2008, the Company’s wholly-owned subsidiary, National Coal Corporation, completed the sale of the real and personal property assets that comprised its Straight Creek mining operations in Bell, Leslie and Harlan Counties, Kentucky to Xinergy Corp. (“Xinergy”) for $11,000,000 in cash in accordance with the terms and conditions of a Purchase Agreement entered into among the parties on February 8, 2008 (the “Purchase Agreement”). In addition to the receipt of the purchase price for the assets, the transaction also resulted in the return of approximately $7,400,000 in cash that was previously pledged to secure reclamation bonds and other liabilities associated with the Straight Creek operation, and relieved the Company of approximately $3,600,000 in reclamation liabilities, and approximately $2,700,000 of equipment related debt assumed by Xinergy in the transaction. The Company recorded a loss of $365,025 as a result of the transaction.
The Company used a portion of the sale proceeds to repay the $10,000,000 senior secured credit agreement entered into in October 2006 with Guggenheim Corporate Funding, LLC, as administrative agent, which indebtedness otherwise would have matured in December 2008 (see Note 8).
Xinergy Corp. was founded and is controlled by Jon Nix, who is a founder, significant stockholder, and former officer and director of National Coal. Mr. Nix served as a director of National Coal Corp. from January 2003 until July 2007, and as Chairman of the Board from March 2004 until July 2007. Mr. Nix also served as the Company’s President and Chief Executive Officer from January 2003 until August 2006.
The major categories of assets and liabilities associated with the Straight Creek mining property recorded in the balance sheet as of December 31, 2007 are as follows:
Revenue and net losses attributable to the Straight Creek operations were $5.0 million and $(2.4) million, $35.4 million and $(3.1) million, and $46.0 million and $(9.7) million in 2008, 2007 and 2006, respectively.
4. Inventory
Inventory at December 31 is as follows:
5. Property, Plant, Equipment, and Mine Development
Property, plant, equipment and mine development as of December 31 follows:
Mining equipment includes approximately $3,871,650 and $593,000 of gross assets under capital leases at December 31, 2008 and 2007, respectively.
Depreciation, depletion, amortization and accretion expense for the years ended December 31, 2008, 2007 and 2006 was primarily related to the cost of coal sales for the years then ended. Depreciation expense, which includes amortization of assets under capital leases, was $12,426,162, $12,788,128, and $13,889,816 for the years ended December 31, 2008, 2007, and 2006, respectively. Depletion expense related to mineral rights and amortization of mine development costs was $3,126,762, $2,509,230, and $997,969 for the years ended December 31, 2008, 2007, and 2006, respectively.
On November 12, 2007, the Company received $2 million from the sale of certain real property and mineral leases at Pine Mountain, an idle mining complex located in Kentucky, and an additional $1 million from the sale to the same purchaser of an option entitling it to purchase for $10.00 the remaining, additional properties at Pine Mountain. The Company recognized a gain of approximately $745,000 on the sale of the certain real property and mineral leases at Pine Mountain and deferred recognition of the $1.0 million proceeds on the remaining additional properties until the option is exercised and the additional properties are sold. As of December 31, 2008, the option has not been exercised
On September 18, 2006, the Company entered into a sale-leaseback transaction with First National Capital Corporation’s assignee, GATX Financial Corporation, involving the Company’s highwall miner initially purchased in February 2006. The Company sold the highwall miner for approximately $6.4 million and recorded a deferred gain of approximately $875,000 which is being recognized over the forty-two month term of the operating lease. The lease is a “net” lease and requires that the Company maintain and insure the equipment as well as pay rental payments of $166,568 per month. As a condition of the lease, the Company provided two standby letters of credit totaling $1,288,883 in lieu of security deposits which are 100% collateralized with cash on deposit at two financial institutions. Pursuant to the sale of its Straight Creek operation, the Company is sub-leasing the highwall miner to Xinergy for $166,568 per month, and holds a $1.4 million deposit in escrow, which is classified in the non-current portion of restricted cash at December 31, 2008.
At maturity, the Company has the option of purchasing the highwall miner or extending the lease for an additional twelve month term, both at the then-fair market value, or allowing the lease to expire, at which time the Company would be responsible for the expense of transporting the highwall miner to a lessor designated location within the continental United States.
6. Other Noncurrent Assets
Other noncurrent assets at December 31 are as follows:
7. Accrued Expenses
Accrued expenses at December 31 are as follows:
At December 31, 2008, the legal settlement reserve represents an accrual for a case that was settled in early 2009.
8. Debt and Financing Arrangements
Long-term debt obligations of the Company, excluding capital leases, consist of the following as of December 31:
Maturities of long-term debt for the next five years and thereafter follow:
The Company had deferred financing costs of $4,779,439 and $6,669,703 at December 31, 2008 and 2007, respectively. The Company recorded $823,343 and $1,002,214 of amortization related to deferred financing costs in 2008 and 2007, respectively. Additionally, the Company wrote off deferred financing charges of $1.6 million in 2008 associated with the extinguishment of debt. This amount is included in other expense in the accompanying statement of operations.
10.5% Senior Secured Notes Due 2010
On December 29, 2005, the Company issued $55.0 million of 10.5% Senior Secured Notes due 2010 and warrants to purchase a total of 1,732,632 shares of the Company’s common stock. The issue consisted of 55,000 units, with each unit comprised of one $1,000 principal amount note due 2010 and one warrant, which entitles the holder to purchase 31.5024 shares of the Company’s common stock at an exercise price of $8.50 per share, subject to adjustment. The warrants are subject to mandatory conversion if the price of the Company’s common stock remains above $12.75 for more than nineteen days out of a consecutive thirty day trading period. The warrants will be exercisable at any time on or after their first anniversary date and will expire on December 15, 2010. Net proceeds from this sale were approximately $52.1 million. The Company immediately used approximately $22.1 million of the proceeds to repay existing indebtedness. During 2006, the Company used approximately $2.0 million to purchase a forty-two mile rail line in Tennessee, approximately $8.3 million as collateral to support reclamation bonds, and $19.7 million to purchase other equipment, refurbish preparation facilities and rail load-outs, and provide working capital.
The indenture allows the Company to incur additional indebeteness a Term Loan Credit Facility in the amount of $10.0 million, but limits further indebtedness unless certain fixed charge coverage ratios are maintained on a pro forma basis. Please refer to the Term Loan Credit Facility note below for a discussion of our entrance into such a credit facility. The fixed charge coverage ratio is defined as the ratio of net income (loss) plus (i) fixed charges, (ii) depreciation, depletion and amortization, (iii) taxes, (iv) extraordinary losses, and (v) other non-cash income and expenses to fixed charges defined to include 25% of capital expenditures made by the Company and its subsidiaries. To incur additional indebtedness, the Company must maintain a fixed charge coverage ratio of 2.0 to 1 for 2006, 2.25 to 1 for 2007, and 2.5 to 1 for the remaining term of the Notes. The indenture also restricts payment of dividends on the Company’s common stock. Notes issued under the indenture are guaranteed fully and unconditionally as well as jointly and severally by the Company, which has no independent assets or operations, and each of its wholly-owned subsidiaries with the exception of National Coal of Alabama.
In connection with the December 29, 2005 issuance of notes, the Company entered into a separate registration rights agreement with the purchasers. Pursuant to the separate registration rights agreement, the Company agreed to file an exchange offer registration statement registering the resale by the purchasers of all of the notes and attached warrants. Pursuant to the separate registration rights agreement, the Company filed two registration statements with the Securities and Exchange Commission in May 2006, which were declared effective on July 28, 2006. On September 5, 2006, the Company exchanged $51 million of the total $55 million 10.5% Senior Secured Notes due 2010 for $51 million in new Notes, dated August 31, 2006, which are registered for resale with the Securities and Exchange Commission. The new Notes are issued under substantially the same terms as the old Notes.
During 2008, the Company exchanged notes in the aggregate principal amount of $13 million and accrued interest of $161,783 for 1,855,935 shares of common stock and recorded a loss on extinguishment of debt of $504,392.
12% Notes Payable Due in 2012
On October 19, 2007, NCA completed $60 million in private placements through the issuance of Senior Secured Notes (the “12% Notes due 2012”) to TCW Energy Fund XIV, L.P., TCW Energy Fund XIV-A, L.P. and TCW Energy Fund XIV (Cayman), L.P. pursuant to a note purchase agreement dated October 19, 2007, among NCA, the Holders and TCW Asset Management Company (“TAMCO”). The 12% Notes due 2012 have a maturity date of October 19, 2012 and accrue interest at the rate of 12% per annum due quarterly. In lieu of paying interest due on the 12% Notes due 2012 on each quarterly payment date in full in cash, NCA may elect to pay a portion of such interest in cash equal to the amount of interest which would be owing on such quarterly payment date if the interest rate had been 9% per annum, and to borrow the remaining portion from the Holders in the form of additional loans made through the increase of the principal amounts of the 12% Notes due 2012.
NCA violated its loan covenants related to its 12% Notes due 2012 in each of the second through fourth quarters of 2008. On August 13, 2008, November 12, 2008, and March 26 (Note 20), NCA received waivers of all existing defaults and covenant violations and obtained amended terms for certain covenants through December 31, 2009, as follows:
(i) the fixed charge coverage ratio minimum requirement of 1.00 to 1.00 has been reduced for all fiscal quarters in 2009 to minimum requirements of 0.65 to 1.00 for the fiscal quarter ending March 31, 2009 and 0.75 to 1.00 for each fiscal quarter ending June 30, 2009, September 30, 2009 and December 31, 2009; and
(ii) the current ratio minimum requirement of 1.00 to 1.00 has been reduced for all fiscal quarters in 2009 to minimum requirements of 0.65 to 1.00 for the fiscal quarter ending March 31, 2009 and 0.80 to 1.00 for each fiscal quarter ending June 30, 2009, September 30, 2009 and December 31, 2009; and
(iii) the minimum EBITDA requirement has been reduced from $3,000,000 for the fiscal quarter ending December 31, 2008 to minimum requirements of $2,000,000 for the fiscal quarter ending March 31, 2009 and $2,250,000 for each fiscal quarter ending June 30, 2009, September 30, 2009 and December 31, 2009; and
(iv) the Debt to EBITDA ratio requirement set forth in the Note Agreement has been eliminated for the fiscal quarters ending March 31, 2009, June 30, 2009, September 30, 2009 and December 31, 2009; and
(v) in lieu of paying interest due March 29, 2009, the Company has elected to borrow the full amount of the interest from the holders in the form of a PIK (“Payment in Kind”) loan in principal amount equal to such interest of approximately $1.8 million.
Management expects NCA to be in compliance with its debt covenants during 2009 and, accordingly, has classified the related debt as long-term in the accompanying balance sheet.
On each quarterly payment date from and after March 2008, NCA is required to make a principal payment in respect of the 12% Notes due 2012 in an aggregate amount equal to the adjusted net cash flow for the applicable quarter (as specified in the note purchase agreement), provided that in no event shall NCA be required to make a payment that results in its having cash and cash equivalents (exclusive of any cash and cash equivalents that have been pledged to secure other obligations permitted under the note purchase agreement or that otherwise constitutes “restricted cash” permitted under the note purchase agreement) of less than $2,000,000. NCA is also required to repay outstanding amounts upon the sale of collateral approved by the Holders of a majority of
the aggregate unpaid principal amount under the 12% Notes due 2012 and upon the receipt of certain casualty insurance proceeds. In addition, NCA will be required to pay a “make-whole” amount or incur a prepayment premium in the event that it prepays the Notes prior to their stated maturity. During 2008, NCA was not required to make any payments pursuant to the aforementioned provisions, nor is any payment expected to be made in 2009.
Pursuant to the terms of the note purchase agreement and related security and pledge agreements, all dated October 19, 2007, NCA granted the holders a security interest in all of the company’s assets to secure repayment of the obligations arising under the note purchase agreement and related agreements, and established a debt service reserve account equal to six months of interest on the then outstanding aggregate principal amount of the Notes. The 12% Notes due 2012 are not guaranteed by National Coal Corp., National Coal Corporation or its subsidiaries.
As additional consideration to the holders, NCA conveyed to the Holders an Overriding Royalty Interest with respect to all coal mined by NCA in the state of Alabama. Pursuant to the Conveyance of Overriding Royalty Interest (“ORRI Agreement”), dated October 19, 2007, NCA agreed to pay the holders of the interest a royalty on 18.5 million tons of coal mined and sold by NCA, in an amount equal to (i) $2.00 per ton of coal mined and sold while the obligations remain outstanding under the note purchase agreement, and (ii) an amount equal to 1% of the gross sales price of coal mined and sold annually, subject to a one million ton minimum, after repayment of the obligations under the note purchase agreement. The present value of the expected cash flows associated with the Overriding Royalty Interest, estimated at $9,321,873, reflecting a discount rate of 16.83%, was recorded as a liability and as a discount to the 12% Notes due 2012. During 2008, the Company recorded an additional $0.5 million of interest expense associated with: (i) a change in the estimated gross sales price of coal mined and sold after repayment of the obligations under the note purchase agreement of the Company’s future overriding royalty obligation, net of (ii) a reduction in production assumptions, thereby deferring certain cash flows to future dates. Additionally, the Company did not meet the one million minimum annual tons produced and sold requirement as specified in the ORRI Agreement, and was required to pay an interest penalty of $0.2 million in 2008.
NCA also paid to TAMCO a commitment fee of $900,000, which is equal to 1.5% of the aggregate commitments of $60 million under the note purchase. The Company also paid fees of $1.1 million and 175,000 shares of the Company’s common stock to a broker who assisted with this transaction. These amounts were recorded as deferred financing costs in the accompanying balance sheets.
Each of NCC Corp. and NCA is an “unrestricted subsidiary” within the meaning of the Company’s 10.5% Senior Secured Notes due 2010, which means that: (i) these unrestricted subsidiaries cannot have any indebtedness for which National Coal Corp. or any of its other subsidiaries is directly or indirectly liable, or which National Coal Corp. or any of its other subsidiaries guarantees or otherwise provides credit support; (ii) these unrestricted subsidiaries cannot be party to any agreement with National Coal Corp. or any of its other subsidiaries unless the terms of any such agreement are no less favorable to National Coal Corp. or such other subsidiaries than those that might be obtained at the time from persons who are not the Company’s affiliates; (iii) none of National Coal Corp. or its other subsidiaries can have any direct or indirect obligation to subscribe for additional equity interests of the unrestricted subsidiaries or maintain or preserve the unrestricted subsidiaries’ financial condition or cause them to achieve any specified levels of operating results.
NCA is restricted in its ability to distribute cash to the other subsidiaries of the Company, and to the Company consolidated companies for use in their operations under the terms of the TCW credit facility. On an annual basis, NCA can distribute cash to the Company only if it meets certain EBITDA based operating requirements for the immediately preceding fiscal year. Additionally, the Company has entered into a management services agreement with NCA that compensates National Coal Corp. for services that it provides to NCA, and a tax sharing agreement that requires NCA to pay to National Coal Corp. 75% of its tax liability. In fiscal 2009, however, the Company anticipates NCA’s operations to provide cash for use in its other operations limited to the annual management services fee.
Term Loan Credit Facility
On October 12, 2006, the Company’s wholly-owned subsidiary, National Coal Corporation, entered into a Term Loan Credit Facility that provides for borrowings of $10.0 million with Guggenheim Corporate Funding, LLC to fund general operating and working capital needs (the “Term Loan Credit Facility”). The Company borrowed $8.0 million in 2006 and $2.0 million in March 2007. The Company’s obligations under the credit facility are secured by a first priority senior lien on substantially all of the Company’s assets.
Initially, the credit agreement provided that all amounts under the facility would be due and payable in March 2010 and would bear interest at a rate equal to, at the Company’s option, the Eurodollar Rate plus 3.5% or the Base Rate (which approximates the prime rate) plus 2.5%. The term loan credit facility also contained financial covenants and default provisions including that the Company maintain minimum levels of EBITDA and liquidity, maintain minimum interest coverage ratios, not exceed maximum leverage ratios, and that it limit certain future categories of transactions such as the incurrence of additional indebtedness and the sale of assets.
In March 2007, Guggenheim agreed to amend the credit agreement and reset the financial covenants, as a result of which the applicable margin on the credit facility was increased by 1.0%. At June 30, 2007, the Company was not in compliance with certain financial covenants under the credit agreement and on August 15, 2007, Guggenheim agreed to a further amendment under which (1) the maturity date was changed to December 31, 2008, (2) the interest rate was changed to 12%, (3) fees equal to 5% of all balances outstanding at December 31, 2007 and 10% of all amounts outstanding at June 30, 2008 were provided for, (4) the EBITDA financial covenant was reset, and (5) prepayment penalties were eliminated.
On October 19, 2007, the lenders party to the credit agreement assigned to Steelhead Offshore Capital, LP, Big Bend 38 Investments, L.P., and J-K Navigator Fund, L.P., the Company’s outstanding obligations to repay funds loaned to the Company pursuant to the credit agreement in the aggregate principal amount of $10,000,000 and, to the extent permitted to be assigned under applicable law, all claims, suits, causes of action and any other right of the lenders against any person arising under or in connection with the credit agreement. Guggenheim remained as Administrative Agent under the credit agreement.
On October 19, 2007, the parties to the credit agreement entered into a Waiver and Amendment No. 3 (the “Waiver and Amendment”) to the credit agreement, pursuant to which the parties agreed to waive and amend certain provisions of the credit agreement. Pursuant to the Waiver and Amendment, Guggenheim and each lender waived certain fees related to amounts outstanding under the term loan facility as of December 31, 2007, the Company’s compliance with certain minimum consolidated EBITDA requirements for the fiscal quarters ending September 30, 2007 and December 31, 2007, and the registration and processing fee due to Guggenheim solely with respect to the assignment and acceptance of the Company’s outstanding obligations to Steelhead Offshore Capital, LP, Big Bend 38 Investments, L.P., and J-K Navigator Fund, L.P. The Waiver and Amendment also amended various restrictive covenants in the credit agreement, including covenants to permit the Company to consummate the acquisition of Mann Steel Products, Inc. and incur the debt financing for such acquisition. Fees equal to 10% of all amounts outstanding under the credit agreement at June 30, 2008, provided for in the second amendment dated August 15, 2007, remain in place. The Company did not accrued any amounts relative to these fees as management did not believe it probable that the Company would be required to pay the fees due to its belief that the term loan credit agreement would be refinanced prior to June 30, 2008.
On October 19, 2007, the parties to the credit agreement also entered into a letter agreement (the “Lender Fee Letter”) pursuant to which the Company agreed, at its election and as compensation for the Waiver and Amendment and assignment agreements, (i) to issue warrants (the “Refinance Fee Warrants”) on or before June 30, 2008 to purchase up to 750,000 shares of the Company’s common stock at an exercise price of $3.00 per share with a term through December 31, 2011 or (ii) make a cash payment on or before October 17, 2008 in an amount equal to the Black-Scholes value of a warrant, exercisable on or before December 31, 2011, for up to 750,000 shares of the Company’s common stock at an exercise price of $3.00 per share, obtained using the “OV” function on Bloomberg Financial Markets and reflecting the calculation assumptions set forth in the Lender Fee Letter, to Steelhead Offshore Capital, LP, Big Bend 38 Investments L.P., and J-K Navigator Fund, L.P. In the event that the Company issues the Refinance Fee Warrant, the shares issuable upon exercise of these warrants shall have registration rights similar to those provided in the Registration Rights Agreement entered into in connection with the October 19, 2007 equity financing (see Note 11, Stockholders’ Equity (Deficit). Fees and expenses totaling approximately $323,000 were expensed as incurred and the value of the warrant was capitalized as deferred financing fees to be amortized over the remaining life of the loan using the effective interest method.
The Company elected to issue the Refinance Fee Warrant pursuant to the Lender Fee Letter and, on December 31, 2007, entered into the Warrant Agreement with the parties to the letter agreement.
On November 16, 2007, the lenders party to the credit agreement entered into a Waiver under which the EBITDA financial covenant was waived for the fiscal quarters ending March 31, 2008 and June 30, 2008. As of April 2, 2008, the Company repaid the $10 million credit agreement with a portion of the proceeds from the sale of its Straight Creek properties, and terminated this agreement.
Installment Purchase Obligations and Equipment Notes
During 2008, the Company financed equipment and vehicles with an aggregate principal value of approximately $3.6 million. The notes require payments over 36 to 55 months with fixed interest rates ranging from of 4.02% to 8.69%. The obligations under the notes are secured by the purchased assets.
During 2007, the Company financed equipment and vehicles with an aggregate principal value of approximately $4.9 million. These installment sale contracts require payments over 36 to 60 months at fixed interest rates ranging from 5.97% to 7.99%. The obligations under the installment sale contracts are secured by the equipment purchased.
During 2007, the Company refinanced equipment with an aggregate principal value of approximately $0.7 million formerly acquired under various capital leases. These installment sale contracts require payments over 36 months at fixed interest rates ranging from 5.29% to 8.75%. The obligations under the installment sale contracts are secured by the equipment purchased.
During 2006, the Company financed equipment and vehicles with an aggregate principal value of approximately $1.8 million. These installment sales contracts require payments over 36 to 60 months at fixed interest rates ranging from 4.48% to 9.28%.
Approximately $2.6 million of equipment related debt was assumed by Xinergy Corp. on March 31, 2008, as a result of the sale of the Company’s Straight Creek, Kentucky properties.
9. Leases
The Company leases mining and certain other equipment under noncancelable lease agreements with terms up to five years. Rental expense for equipment under operating lease agreements with initial lease terms of one year or greater was approximately $2,034,529, $2,102,694 and $1,011,323 for the years ended December 31, 2008, 2007, and 2006, respectively.
The Company entered into capital lease agreements with various equipment suppliers for mining equipment totaling $3,325,500, $248,900 and $833,827 during 2008, 2007 and 2006, respectively. The leasing periods for these arrangements is typically 24 to 36 months.
Future minimum lease payments for noncancelable leases with initial terms of one year or greater at December 31, 2008 are as follows:
10. Asset Retirement Obligations
The following table summarizes the activity with respect to the Company’s asset retirement obligations for the years ended December 31:
11. Stockholders’ Equity (Deficit)
Series A Cumulative, Convertible Preferred Stock
During 2008, 2007 and 2006, the holders of 356.44, 426.10 and 550.90 shares of Series A preferred stock, with liquidation preferences totaling $5,346,600, $6,391,500 and $8,260,206, plus accrued dividends of $131,712, $159,152 and $65,439 converted their shares into 946,168, 1,124,121 and 1,386,128 shares of the Company’s common stock, respectively. During 2008, the Company offered an additional 154,573 common shares as an inducement to convert Series A preferred stock into common stock. During 2007, the Company offered $1,702,154 as a cash inducement and an additional 431,258 common shares as an inducement to convert Series A preferred stock into common stock. EITF Topic D-42, The effect on the Calculation of Earnings per Share for the Redemption or Induced Conversion of Preferred Stock requires that if convertible preferred stock is converted to other securities pursuant to an inducement offer, the Company should record the excess of (1) the fair value of all securities and other consideration transferred to the holders of the convertible preferred stock over (2) the fair value of securities issuable pursuant to the original conversion terms as an increase to net loss to arrive at net loss attributable to common shareholders. Accordingly, the Company recorded deemed dividends of $593,563 and $3,070,185 as a result of the aforementioned inducements in 2008 and 2007, respectively. Additionally, during 2007, the Company sold common stock in a private placement that triggered a reduction in the preferred stock conversion rate; in accordance with EITF Issue No. 98-5, Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios, the Company recorded a deemed dividend of $988,173 associated with the resolution of this beneficial conversion contingency.
As of December 31, 2008, all remaining Series A preferred stock had been converted to common stock.
National Coal Corp. Common Stock
During 2008, the Company purchased a 1,000 acre mineral and surface tract in eastern Tennessee that includes approximately 2.3 million tons of high quality coal. The purchase price was $7.0 million of which $2.0 million was paid in cash and $5.0 million in the issuance of 756,430 shares of the Company’s common stock.
During 2008, the Company completed the sale of 2,332,000 shares of common stock in a private placement at a price of $4.65 per share for gross proceeds of $10,843,798.
During 2007, the Company completed the sale of 9,625,669 shares of common stock in private placements at prices ranging between $3.00 to $4.65 per share, for gross proceeds of $35,797,686, including 3,866,968 shares sold in connection with the Mann Steel Acquisition (see Note 3). All common shares have been subsequently registered pursuant to registration rights agreements.
During 2006, the Company issued 101,503 shares of common stock for gross proceeds of $897,018.
Outstanding Stock Purchase Warrants
At December 31, 2008, the following warrants for the purchase of National Coal Corp. common stock were outstanding:
* Crestview Warrants have been adjusted per the anti-dilution provision in the warrant agreement
The Crestview warrants and the Bond warrants are subject to mandatory conversion if the price of the Company’s common stock remains above $12.50 for more than thirty days.
The Crestview Warrants are subject to price and share adjustment on: a) a weighted average basis when the Company issues common stock at a price below $6.60 per share or b) a full adjustment basis when the Company issues warrants below the current strike price. Based upon the December 31, 2007 warrant issuance discussed below, the warrants have adjusted to 396,620 shares at a price of $3.00 per share.
During 2008, 3,000 of the Bond Warrants were converted into 14,176 shares of the Company’s common stock.
On October 19, 2007, as part of capitalizing its newly formed subsidiary, NCC Corp., the Company issued warrants to purchase 250,000 shares of National Coal Corp. common stock at a per share price of $4.00 and a term expiring on December 31, 2010 (the “Alabama Warrant”). NCC Corp. assigned this warrant to National Coal of Alabama, Inc., which further assigned the warrant to the holders of the 12% Notes Payable due 2012. These warrants were valued at $263,067 using the Black-Scholes Option Pricing Model and recorded in the equity section of the accompanying balance sheet. Pursuant to a registration rights agreement, these warrant shares were subsequently registered.
On December 31, 2007, the Company issued the Refinance Fee Warrant to three parties which provides the right to purchase up to 750,000 shares of National Coal Corp. common stock at a price per share of $3.00 through December 31, 2011 (see Note 8).
12. Fair Value of Financial Instruments
The following methods and assumptions were used by the Company in estimating its fair value disclosures for financial instruments at December 31, 2008, and 2007:
Cash and accounts receivable: The carrying amount approximates fair value because of the short maturity of these instruments.
Debt: The fair value of the Company’s long-term debt is estimated based on the quoted market prices for similar issues or on the estimated current rate of incremental borrowing available to the Company for similar liabilities.
The estimated fair values of the Company’s financial instruments at December 31 are as follows:
13. Concentrations of Credit Risk and Major Customers
Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of accounts receivable. Accounts receivable are from brokers or purchasers of the Company’s coal with payment terms that typically do not exceed 20 days. The Company routinely performs credit evaluations of customers purchasing on account and generally does not require collateral.
For the year ending December 31, 2008, two utility providers and one industrial customer represented approximately 34%, 21% and 14% of the Company’s revenues, respectively. The following table lists the percentage of each type of revenue generated by market:
14. Income Taxes
At December 31, 2008, the Company had federal and state net operating loss (“NOL”) carryforwards of $175.6 million that will begin to expire in 2015. The use of deferred tax assets including federal net operating losses and credits are limited to future taxable earnings. Based on an analysis of future taxable income, management believes that there is not sufficient evidence at December 31, 2008 indicating that the results of operations will generate sufficient taxable income to realize the net deferred tax asset in years beyond 2008. As a result, a valuation allowance has been provided for the entire net deferred tax asset related to future years, including loss and credit carryforwards. The valuation allowance increased by $15,450,912 and $6,779,997 in 2008 and 2007, respectively.
The net deferred income taxes as of December 31 include the following amounts of deferred income tax assets and liabilities:
The Company’s deferred income taxes relate principally to deferred revenue, deferred compensation and federal and state net operating loss and credit carryforwards. The provision for income taxes differs from the amount computed by applying the statutory federal income tax rate to income before the provision for income taxes. The sources and tax effects of the differences are as follows:
As a result of implementing FIN 48, effective January 1, 2007, the Company did not have any unrecognized tax benefits or liabilities, or any associated amounts for interest and penalties. As such, there was no effect on its financial condition or results of operations as of and for the year ended December 31, 2008.
The Company has no material unrecognized tax benefits or any known material tax contingencies at December 31, 2008.
We recognize interest and penalties related to uncertain tax positions in income tax expense, which was $0 for 2008, 2007 and 2006.
The Company files income tax returns in the U.S. federal jurisdiction and various state jurisdictions. There are no income tax examinations currently in process. With few exceptions, the Company is no longer subject to U.S. federal examinations or state and local income tax examinations by tax authorities for years before 2003.
15. Earnings per Share
Basic earnings or loss per share are computed by dividing net income by the weighted average number of common shares outstanding during the year. Diluted earnings per share are computed similarly to basic earnings per share except that they reflect the potential dilution that could occur if dilutive securities or other obligations to issue common stock were exercised or converted into common stock. Diluted earnings or loss per share includes dilutive common stock equivalents, using the treasury stock method, and assumes that the potentially dilutive instruments were converted into common stock at the beginning of the year or upon issuance. Stock options with exercise prices greater than the average fair market price for a period, which are defined as anti-dilutive, are not included in the diluted earnings (loss) per share calculations because of their anti-dilutive effect. In periods of losses, diluted loss per share is computed on the same basis as basic loss per share as the inclusion of any other potential shares outstanding would be anti-dilutive.
For the years ended December 31, 2008, 2007, and 2006, 1,448,597, 189,117 and 3,866,360, respectively, potentially dilutive shares of the Company from warrants, convertible preferred stock and stock options were not included in the computation of diluted loss per share because to do so would be anti-dilutive.
The computations for basic and diluted loss per share from continuing operations for the period ending December 31 are as follows:
16. Stock-based Compensation Plans
The Company’s 2004 Option Plan (the “Plan”) was authorized by the Board of Directors of the Company in March 2004, and amended in January 2005. Under the terms of the Plan, stock options may be granted to officers, directors, employees, and others. At December 31, 2007, 4,450,000 shares of common stock were authorized for issuance under the Plan. Shares subject to awards that expire unexercised or are otherwise terminated, again become available for awards. Upon exercise, stock is issued from unissued or treasury shares. The grant price of an option under the Plan may not be less than the fair market value of the common stock subject to such option on the date of grant. Options have a maximum life of ten years and generally vest 25% per year over a four year period.
During the year ended December 31, 2008, 2007 and 2006, the Company recognized compensation expense of $1,349,667, $1,436,996 and $2,235,224, respectively, related to stock options.
The fair value of each option was estimated on the date of the grant using the Black-Scholes option-pricing model with the following weighted average assumptions:
The risk-free interest rate is based on the U.S. Treasury rate for the expected life at the time of grant, volatility is based on the average long-term implied volatilities of peer companies as the Company’s trading history is limited, and the expected term is determined using the simplified method as accepted under Securities and Exchange Commission Staff Accounting Bulletin No. 107 assuming a ten-year original contract term and graded vesting over four years. The weighted-average grant-date fair value of options issued during the years ended December 31, 2008, 2007, and 2006 were $3.43, $1.92 and $3.16, respectively. The total intrinsic value of options exercised during the years ended December 31, 2008 and 2006 was $555,398 and $2,450,313, respectively.
The following table summarizes activity under the Plan for the year ended December 31, 2008:
As of December 31, 2008, there was $1,560,904 of total unrecognized compensation cost related to non-vested stock options granted under the Plan. That cost is expected to be recognized over a weighted average period of 3.34 years. The weighted average remaining contractual term of exercisable options at December 31, 2008 was 1.47 years. The total fair value of shares vested during the years ended December 31, 2008, 2007, and 2006, was $2,548,300, $1,143,942, and $2,762,529, respectively.
17. Commitments and Contingencies
The Company is made a party to legal actions, claims, arbitration and administrative proceedings from time to time in the ordinary course of business. Management is not aware of any pending or threatened proceedings that might have a material impact on its cash flows, results of operations or financial condition.
18. Related Party Transactions
On October 20, 2008, the Company executed employee retention contracts with two executive officers of the Company. These agreements in the aggregate, provide for cash payments of $350,000 upon execution and an additional $100,000 payable on January 31, 2012. These amounts are being expensed over the terms of the agreements. In addition, the agreements provide for a total of 200,000 restricted shares of the Company’s common stock as well as the option to purchase 75,000 additional shares under a three year vesting schedule.
On May 7, 2008, the Company completed the sale of 2,332,000 shares of common stock at a price of $4.65 per share in a private placement for gross proceeds of $10,843,800. Three executive officers participated in the offering and acquired an aggregate of 55,000 of the shares.
On March 31, 2008, the Company’s wholly-owned subsidiary, National Coal Corporation, completed the sale of the real and personal property assets that comprised its Straight Creek mining operations in Bell, Leslie and Harlan Counties, Kentucky to Xinergy Corp. (“Xinergy”) for $11,000,000 in cash in accordance with the terms and conditions of a Purchase Agreement entered into among the parties on February 8, 2008 (the “Purchase Agreement”). In addition to the receipt of the purchase price for the assets, the transaction also resulted in the return of approximately $7,400,000 in cash that was previously pledged to secure reclamation bonds and other liabilities associated with the Straight Creek operation, and relieved the Company of approximately $3,600,000 in reclamation liabilities and approximately $2,600,000 of equipment related debt which were assumed by Xinergy in the transaction.
Xinergy Corp. was founded and is controlled by Jon Nix, who is a founder, significant stockholder, and former officer and director of National Coal. Mr. Nix served as a director of National Coal Corp. from January 2003 until July 2007, and as Chairman of the Board from March 2004 until July 2007. Mr. Nix also served as President and Chief Executive Officer from January 2003 until August 2006.
On October 19, 2007, the CEO and President of the Company, purchased 200,000 shares of the Company’s common stock at a price of $3.00 per share from common stock authorized under the 2004 Stock Option Plan.
On October 19, 2007, Jon Nix, the former Chairman of the Company’s Board of Directors, who is also the former President and CEO, received a commission of $100,000 related to the completion of the acquisition of Mann Steel Products, Inc.
In March 2007, the then-Chairman of the Company’s Board of Directors, who is also the former President and CEO, sold to the current President and CEO for $10.00 the fully vested option to purchase 400,000 shares of National Coal Corp. common stock at $7.00 per share until December 31, 2008. The transaction resulted in $434,493 of additional compensation expense to the Company in the year ended December 31, 2007.
On February 28, 2007, the Company sold an additional 200,000 shares to the Company’s President and CEO for a total price of $930,000.
On June 5, 2006 the Company sold 100,000 shares of National Coal Corp. common stock to the Company’s President and CEO, for a total price of $888,000.
19. Supplemental Guarantor and Non-Guarantor Information
National Coal of Alabama, Inc. and its parent company, NCC Corp. (the “Alabama Companies”), have been designated as “unrestricted subsidiaries” with regard to the 10.5% Senior Secured Notes due 2010 and the Term Loan Credit Facility, which designation exempts them from being guarantors under those facilities. Further, the Alabama Companies do not guarantee any debt in which either National Coal Corp. or National Coal Corporation is the borrower. Conversely, National Coal Corp., National Coal Corporation and its subsidiaries (the “Tennessee Companies”) have been excluded as guarantors under the 12% Notes Payable due 2012.
The following condensed consolidating financial information sets forth the financial position as of December 31, 2008 and results of operations and cash flows for the year ended December 31, 2008 of National Coal Corp. (NCC) and NCA. NCA was acquired on October 19, 2007.
National Coal Corp.
Supplemental Consolidated Balance Sheets
December 31, 2008
National Coal Corp.
Supplemental Consolidated Balance Sheets
December 31, 2007
National Coal Corp.
Supplemental Consolidated Statements of Operations
For the Year Ended December 31, 2008
National Coal Corp.
Supplemental Condensed Consolidated Statements of Cash Flows
For the Year Ended December 31,
National Coal Corp.
Supplemental Condensed Consolidating Statement of Cash Flows
For the Period Ended December 31, 2007
20. Events Subsequent to December 31, 2008
The Company violated its loan covenants related to its 12% Senior Secured Notes due 2012 in the fourth quarter of 2008 and a waiver was received of all existing defaults and covenant violations on March 26, 2009, respectively. Additionally, on March 26, 2009, the credit facility was amended to modify or eliminate certain financial covenant requirements through December 31, 2009.
21. Summary Quarterly Financial Information (Unaudited)
Quarterly financial data for 2008 and 2007 is as follows:
Note: Straight Creek mining operations were disposed of on March 31, 2008.
The above information has been restated for the following errors:
The Company identified errors and inconsistencies in the application of accounting policies at its Alabama subsidiary, particularly as it related to its accounting for asset retirement obligations and the capitalization of certain qualifying repairs such as rebuilds and overhauls to engines, undercarriages and transmissions. As a result of these findings, the Company restated its quarterly results for the
aforementioned items, including respective adjustments to inventory and taxes, as well as several immaterial adjustments that had been passed in previous quarters, principally interest expense.
Note: National Coal of Alabama was acquired on October 19, 2007.
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
None
Item 9A.
Item 9A. Controls and Procedures.
Controls and Procedures
Members of our management, including our President and Chief Executive Officer, Daniel A. Roling, and Chief Financial Officer, Michael R. Castle, 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, 2008, the end of the period covered by this report. Based upon that evaluation, Messrs. Roling and Castle concluded that our disclosure controls and procedures were effective as of December 31, 2008.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that:
(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
(ii) provide reasonable assurance that transactions are recorded as necessary to permit the preparation of financial statements in accordance with U.S. generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of management and directors; and
(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation of effectiveness to future periods are subject to risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2008. In making this assessment, we used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment and those criteria, we have concluded that our internal control over financial reporting was effective as of December 31, 2008.
Ernst & Young LLP, the independent registered public accounting firm who also audited the Company’s consolidated financial statements, has issued an attestation report on the Company’s internal control over financial reporting which is included herein.
Changes In Internal Control Over Financial Reporting
During the fourth quarter, we identified and made modifications to enhance controls related to the financial statement closing process. As a result, we identified errors and inconsistencies in the application of company policies at our Alabama subsidiary, particularly as it related to our accounting for asset retirement obligations and the capitalization of certain qualifying repairs such as rebuilds and overhauls to engines, undercarriages and transmissions. As a result of these findings, we restated our quarterly results for the aforementioned items, including respective adjustments to inventory and taxes, as well as several immaterial adjustments that had been passed in previous quarters, principally interest expense. As a result of this remediation and corresponding restatement of our quarterly results, management believes that we had a material weakness for the nine months ending September 30, 2008. However, we believe such material weakness was remediated as of December 31, 2008, due to the aforementioned control modifications.
There were no other 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 December 31, 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B.
Item 9B. Other Information.
None.
PART III
Item 10.
Item 10. Directors, Executive Officers, and Corporate Governance.
The information required by this item is incorporated by reference to National Coal’s Proxy Statement for its 2009 Annual Meeting of Shareholders to be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2008.
Item 11.
Item 11. Executive Compensation.
The information required by this item is incorporated by reference to National Coal’s Proxy Statement for its 2009 Annual Meeting of Shareholders to be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2008.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required by this item is incorporated by reference to National Coal’s Proxy Statement for its 2009 Annual Meeting of Shareholders to be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2008.
Item 13.
Item 13. Certain Relationships, Related Transactions, and Director Independence
The information required by this item is incorporated by reference to National Coal’s Proxy Statement for its 2009 Annual Meeting of Shareholders to be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2008.
Item 14.
Item 14. Principal Accounting Fees and Services.
The information required by this item is incorporated by reference to National Coal’s Proxy Statement for its 2009 Annual Meeting of Shareholders to be filed with the SEC within 120 days after the end of the fiscal year ended December 31, 2008.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules.
(a) The following documents are filed as part of this report:
1. Consolidated Financial Statements
See “Index to Consolidated Financial Statements” in Part II, Item 8 of this Form 10-K.
2. Financial Statement Schedules
All financial schedules are not required under the related instructions, or are inapplicable and therefore have been omitted.
3. Exhibits. See Item 15(b) below.
(b) Exhibits. We have filed, or incorporated into this Form 10-K by reference, the exhibits listed on the accompanying Index to Exhibits immediately following the signature page of this Form 10-K.
(c) Financial Statement Schedule. See Item 15(a) above.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
POWER OF ATTORNEY
The undersigned directors and officers of National Coal Corp. do hereby constitute and appoint Daniel Roling and Michael R. Castle, and each of them, with full power of substitution and resubstitution, as their true and lawful attorneys and agents, to do any and all acts and things in our name and behalf in our capacities as directors and officers and to execute any and all instruments for us and in our names in the capacities indicated below, which said attorney and agent, may deem necessary or advisable to enable said corporation to comply with the Securities Exchange Act of 1934, as amended and any rules, regulations and requirements of the Securities and Exchange Commission, in connection with this Annual Report on Form 10-K, including specifically but without limitation, power and authority to sign for us or any of us in our names in the capacities indicated below, any and all amendments (including post-effective amendments) hereto, and we do hereby ratify and confirm all that said attorneys and agents, or either of them, shall do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
INDEX TO EXHIBITS
* Indicates a management contract or compensatory plan.
(1) Incorporated by reference to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2006.
(2) Incorporated by reference to our Current Report on Form 8-K, filed on October 25, 2007.
(3) Incorporated by reference to our Current Report on Form 8-K, filed February 12, 2008.
(4) Incorporated by reference to our Current Report on Form 8-K, filed February 28, 2008.
(5) Incorporated by reference to our Registration Statement on Form 10-SB filed June 25, 1999.
(6) Incorporated by reference to our Current Report on Form 8-K, filed August 7, 2003.
(7) Incorporated by reference to our Registration Statement on Form SB-2 (File No. 333-120146).
(8) Incorporated by reference to our Current Report on Form 8-K filed on July 27, 2007.
(9) Incorporated by reference to our Annual Report on Form 10-K for the fiscal year ended December 31, 2005.
(10) Incorporated by reference to our Registration Statement on Form S-3 (File No. 333-142403).
(11) Incorporated by reference to our Current Report on Form 8-K, filed December 28, 2007.
(12) Incorporated by reference to our Current Report on Form 8-K, filed January 3, 2008.
(13) Incorporated by reference to our Current Report on Form 8-K, filed December 3, 2007.
(14) Incorporated by reference to our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2005.
(15) Incorporated by reference to our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2005.
(16) Incorporated by reference to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2006.
(17) Incorporated by reference to our Current Report on Form 8-K, filed May 29, 2008.
(18) Incorporated by reference to our Current Report on Form 8-K, filed July 21, 2008.
(19) Incorporated by reference to our Current Report on Form 8-K, filed October 24, 2008.
(20) Incorporated by reference to our Current Report on Form 8-K, filed July 9, 2008.
(21) Incorporated by reference to our Current Report on Form 8-K, filed May 13, 2008.
(22) Incorporated by reference to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2008.