Item 1. Business.
CONSOL Energy’s History
We are a multi-fuel energy producer and energy services provider primarily serving the electric power generation industry in the United States. The electric power industry generates over two-thirds of its output by burning coal or gas, the two fuels we produce. During the year ended December 31, 2009, we produced high-British thermal unit (Btu) bituminous coal from 16 mining complexes in the United States. Coal produced from our mines has a high-Btu content which creates more energy per unit when burned compared to coals with lower Btu content. As a result, coals with greater Btu content can be more efficient to use. We are the majority shareholder (83.3%) of CNX Gas Corporation (CNX Gas). CNX Gas primarily produces pipeline-quality coalbed methane gas from our coal properties in the Northern and the Central Appalachian basin, and oil and gas from properties in the Appalachian and Illinois Basins. We believe that the use of coal and gas will continue to be the principal way in which the United States generates its electricity.
Historically, we rank among the largest coal producers in the United States based upon total revenue, net income and operating cash flow. Our production of approximately 59 million tons of coal in 2009 accounted for approximately 6% of the total tons produced in the United States and approximately 13% of the total tons produced east of the Mississippi River during 2009. We are one of the premier coal producers in the United States by several measures:
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We mine more high-Btu bituminous coal than any other United States producer;
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We are the largest coal producer east of the Mississippi River;
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We control the second largest amount of recoverable coal reserves among United States coal producers; and
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We are the largest United States producer of coal from underground mines.
Our subsidiary, CNX Gas, also ranks as one of the largest coalbed methane gas companies in the United States based on both its proved reserves and its current daily production. Our position as a gas producer is highlighted by several measures:
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Our principal coalbed methane operations produce gas from coal seams (single layers or strata of coal) with a high gas content;
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We produced 94.4 billion cubic feet of gas in the year ended December 31, 2009;
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At December 31, 2009, we had 3,926 net producing wells; and
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We controlled approximately 1.9 trillion cubic feet of net proved reserves at December 31, 2009, of which 86% were coalbed methane reserves.
Additionally, we provide energy services, including river and dock services, terminal services, industrial supply services, coal waste disposal services and land resource management services.
CONSOL Energy was organized as a Delaware corporation in 1991. We use “CONSOL Energy” to refer to CONSOL Energy Inc. and our subsidiaries, unless the context otherwise requires.
Industry Segments
CONSOL Energy has two principal business units: Coal and Gas. The principal activities of the Coal unit are mining, preparation and marketing of steam coal, sold primarily to power generators, and of metallurgical coal, sold to steel and coke producers. The Coal unit includes four reportable segments. These reportable segments are Northern Appalachian, Central Appalachian, Metallurgical and Other Coal. Each of these reportable segments includes a number of operating segments (mines). For the year ended December 31, 2009,
the Northern Appalachian aggregated segment includes the following mines: Blacksville #2, Robinson Run, McElroy, Loveridge, Bailey, Enlow Fork, Mine 84 and Shoemaker. For the year ended December 31, 2009, the Central Appalachian aggregated segment includes the following mines: Jones Fork Complex, the Miller Creek Complex, the Fola Complex and the Terry Eagle Complex. For the year ended December 31, 2009, the Metallurgical aggregated segment includes the following mines: Buchanan and Amonate Complex. The Other Coal segment includes our purchased coal activities, idled mine cost, coal segment business units not meeting aggregation criteria, as well as various other activities assigned to the coal segment but not allocated to each individual mine. The principal activity of the Gas unit is to produce pipeline-quality methane gas for sale primarily to gas wholesalers. CONSOL Energy’s All Other segment includes terminal services, river and dock services, industrial supply services and other business activities, including rentals of building and flight operations. Financial information concerning industry segments, as defined by accounting principles generally accepted in the United States, for the years ended December 31, 2009, 2008 and 2007 is included in Note 25 of Notes to Audited Consolidated Financial Statements included as Item 8 in Part II of this Annual Report on Form 10-K.
Coal Operations
Mining Complexes
During the year ended December 31, 2009, CONSOL Energy had 16 active mining complexes, including a 49% equity affiliate, all located in the United States.
The following map provides the location of CONSOL Energy’s operations by region:
The following table provides the location of CONSOL Energy’s mining complexes and the coal reserves associated with each.
CONSOL ENERGY MINING COMPLEXES
Proven and Probable Assigned and Accessible Coal Reserves as of December 31, 2009 and 2008
(1) The heat value shown for assigned reserves is based on the quality of coal mined and processed during the year ended December 31, 2009. The heat value shown for accessible reserves is based on the same mining and processing methods as for the assigned reserves with adjustments made based on the variability found in exploration drill core samples. The heat values given have been adjusted to include moisture that may be added during mining or processing and for dilution by rock lying above or below the coal seam.
(2) Recoverable reserves are calculated based on the area in which mineable coal exists, coal seam thickness and average density determined by laboratory testing of drill core samples. This calculation is adjusted to account for coal that will not be recovered during mining and for losses that occur if the coal is processed after mining. Reserve calculations do not include adjustments for moisture that may be added during mining or processing, nor do the calculations include adjustments for dilution from rock lying above or below the coal seam. Reserves are reported only for those coal seams that are controlled by ownership or leases.
(3) Harrison Resources is an equity affiliate in which CONSOL Energy owns a 49% interest. Reserves reported equal CONSOL Energy’s 49% proportionate interest in Harrison Resources’ reserves.
Excluded from the table above are approximately 109.2 million tons of reserves at December 31, 2009 that are assigned to projects that have not produced coal in 2009 or 2008. These assigned reserves are in the Northern Appalachia (northern West Virginia), Central Appalachia (Virginia and eastern Kentucky) and Illinois Basin (Illinois) regions. These reserves are approximately 52% owned and 48% leased.
CONSOL Energy assigns coal reserves to each of our mining complexes. The amount of coal we assign to a mining complex generally is sufficient to support mining through the duration of our current mining permit. Under federal law, we must renew our mining permits every five years. All assigned reserves have their required permits or governmental approvals, or there is a high probability that these approvals will be secured.
In addition, our mining complexes may have access to additional reserves that have not yet been assigned. We refer to these reserves as accessible. Accessible reserves are proven and probable unassigned reserves that can be accessed by an existing mining complex, utilizing the existing infrastructure of the complex to mine and to process the coal in this area. Mining an accessible reserve does not require additional capital spending beyond that required to extend or to continue the normal progression of the mine, such as the sinking of airshafts or the construction of portal facilities.
Some reserves may be accessible by more than one mining complex because of the proximity of many of our mining complexes to one another. In the table above, the accessible reserves indicated for a mining complex are based on our review of current mining plans and reflects our best judgment as to which mining complex is most likely to utilize the reserve.
Assigned and unassigned coal reserves are proven and probable reserves which are either owned or leased. The leases have terms extending up to 30 years and generally provide for renewal through the anticipated life of the associated mine. These renewals are exercisable by the payment of minimum royalties. Under current mining plans, assigned reserves reported will be mined out within the period of existing leases or within the time period of probable lease renewal periods.
Coal Reserves
At December 31, 2009, CONSOL Energy had an estimated 4.5 billion tons of proven and probable reserves. Reserves are the portion of the proven and probable tonnage that meet CONSOL Energy’s economic criteria regarding mining height, preparation plant recovery, depth of overburden and stripping ratio. Generally, these reserves would be commercially mineable at year-end price and cost levels.
Reserves are defined in Securities and Exchange Commission (SEC) Industry Guide 7 as follows:
Proven (Measured) Reserves-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 close and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.
Probable (Indicated) Reserves-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.
Spacing of points of observation for confidence levels in reserve calculations is based on guidelines in U.S. Geological Survey Circular 891 (Coal Resource Classification System of the U.S. Geological Survey). Our estimates for proven reserves have the highest degree of geologic assurance. Estimates for proven reserves are based on points of observation that are equal to or less than 0.5 mile apart. Estimates for probable reserves have a moderate degree of geologic assurance and are computed from points of observation that are between 0.5 to 1.5 miles apart.
An exception is made concerning spacing of observation points with respect to our Pittsburgh coal seam reserves. Because of the well-known continuity of this seam, spacing requirements are 3,000 feet or less for proven reserves and between 3,000 and 8,000 feet for probable reserves.
CONSOL Energy’s estimates of proven and probable reserves do not rely on isolated points of observation. Small pods of reserves based on a single observation point are not considered; continuity between observation points over a large area is necessary for proven or probable reserves.
Our reserve estimates are predicated on information obtained from our ongoing exploration drilling and in-mine sampling programs. Data including coal seam elevation, thickness, and, where samples are available, coal quality is entered into a computerized geological database. This information is then combined with data on ownership or control of the mineral and surface interests to determine the extent of reserves in a given area. Reserve estimates include mine recovery rates that reflect CONSOL Energy’s experience in various types of underground and surface coal mines.
CONSOL Energy’s reserve estimates are based on geological, engineering and market data assembled and analyzed by our staff of geologists and engineers located at individual mines, operations offices and at our principal office. The reserve estimates are reviewed and adjusted annually to reflect production of coal from reserves, analysis of new engineering and geological data, changes in property control, modification of mining methods and other factors. Information, including the quantity and quality of reserves, coal and surface control, and other information relating to CONSOL Energy’s coal reserve and land holdings, is maintained through a system of interrelated computerized databases.
Our estimate of proven and probable coal reserves has been determined by CONSOL Energy’s geologists and mining engineers. Our coal reserves are periodically reviewed by an independent third party consultant. The independent consultant has reviewed the procedures used by us to prepare our internal estimates, verified the accuracy of approximately 97% of our property reserve estimates and retabulated reserve groups according to standard classifications of reliability.
CONSOL Energy’s proven and probable coal reserves fall within the range of commercially marketed coals in the United States. The marketability of coal depends on its value-in-use for a particular application, and this is affected by coal quality, such as, sulfur content, ash and heating value. Modern power plant boiler design aspects can compensate for coal quality differences that occur. Therefore, any of CONSOL Energy’s coals can be marketed for power generation.
CONSOL Energy’s reserves are located in northern Appalachia (62%), central Appalachia (14%), the mid-western United States (18%), the western United States (4%), and in western Canada (2%) at December 31, 2009.
The following table sets forth our unassigned proven and probable reserves by region:
CONSOL Energy-UNASSIGNED Recoverable Coal Reserves as of 12/31/09
(1) The heat value estimates for Northern Appalachian and Central Appalachian Unassigned coal reserves include adjustments for moisture that may be added during mining or processing as well as for dilution by rock lying above or below the coal seam. The mining and processing methods currently in use are used for these estimates. The heat value estimates for the Illinois Basin, Western U.S. and Western Canada Unassigned reserves are based primarily on exploration drill core data that may not include adjustments for moisture added during mining or processing or for dilution by rock lying above or below the coal seam.
(2) Recoverable reserves are calculated based on the area in which mineable coal exists, coal seam thickness, and average density determined by laboratory testing of drill core samples. This calculation is adjusted to account for coal that will not be recovered during mining and for losses that occur if the coal is processed after mining. Reserve calculations do not include adjustment for moisture that may be added during mining or processing, nor do the calculations include adjustments for dilution from rock lying above or below the coal seam.
The following table summarizes our proven and probable reserves as of December 31, 2009 by region and type of coal or sulfur content (sulfur content per million British thermal units). Proven and probable reserves include both assigned and unassigned reserves. The table classifies bituminous coal by rank. Rank (High volatile A, B and C) of bituminous coals are classified on the basis of heat value. The table also classifies bituminous coals as medium and low volatile which are classified on the basis of fixed carbon and volatile matter. Coal is ranked by the degree of alteration it has undergone since the initial deposition of the organic material. The lowest ranked coal, lignite, has undergone less transformation than the highest ranked coal, anthracite. From the lowest to the highest rank, the coals are: lignite; sub-bituminous; bituminous and anthracite. The ranking is determined by measuring the fixed carbon to volatile matter ratio and the heat content of the coal. As rank increases, the amount of fixed carbon increases, volatile matter decreases, and heat content increases. Bituminous coals are further characterized by the amount of volatile matter present. Bituminous coals with high volatile matter content are also ranked. High volatile “A” bituminous coals have higher heat content than high volatile “C” bituminous coals. These characterizations of coal allow a user to predict the behavior of a coal when burned in a boiler to produce heat or when it is heated in the absence of oxygen to produce coke for steel production.
CONSOL ENERGY PROVEN AND PROBABLE RECOVERABLE COAL RESERVES
BY PRODUCING REGION AND PRODUCT (IN MILLIONS OF TONS) AS OF DECEMBER 31, 2009
CONSOL ENERGY PROVEN AND PROBABLE RECOVERABLE COAL RESERVES BY PRODUCT
(MILLIONS OF TONS) AS OF DECEMBER 31, 2009
The following table classifies CONSOL Energy coals by rank, projected sulfur dioxide emissions and heating value (British thermal units per pound). The table also classifies bituminous coals as medium and low volatile which is based on fixed carbon and volatile matter.
The following table categorizes the relative Btu values (low, medium and high) for each of CONSOL Energy’s producing regions in Btu’s per pound of coal.
Compliance Compared to Non-Compliance Coal
Coals are sometimes characterized as compliance or non-compliance coal. The term compliance coal, as it is commonly used in the coal industry, refers to compliance only with sulfur dioxide emissions standards and indicates that when burned, the coal will produce emissions that will not exceed 1.2 pounds of sulfur dioxide per million British thermal units (1.2lb S02/MM BTU). A coal considered a compliance coal for meeting sulfur dioxide standards may not meet an emission standard for a different pollutant such as mercury. Moreover, the term compliance coal is always used with reference to the then-current regulatory limit. Clean air regulations that further restrict sulfur dioxide emissions will likely reduce significantly the amount of coal that can be used without post-combustion emission control technologies. Currently, a compliance coal will meet the power plant emission standard of 1.2 lb S02/MM BTU of fuel consumed. At December 31, 2009, 0.7 billion tons, or 15%, of our coal reserves met the current standard as a compliance coal. It is possible that no coal will be considered compliance coal with emission standards restricted to a level that requires emissions-control technology to be used regardless of the coal’s sulfur content. In many cases, our customers have responded to compliance coal requirements by retrofitting flue gas desulfurization systems (scrubbers) to existing power plants. Because these systems remove sulfur dioxide before it is emitted into the atmosphere, our customers are less concerned about the sulfur content of our coal.
As a result of a 1998 court decision forcing the establishment of mercury emissions standards for power plants, the Environmental Protection Agency (EPA) also promulgated a regulatory program for controlling mercury. CONSOL Energy coals have mercury contents typical for their rank and location (approximately 0.07-0.15 parts mercury per million British thermal unit on a dry coal basis). Since CONSOL Energy coals have high heating values, they have lower mercury contents on a weight per energy basis (typically measured in pounds per British thermal units) than lower rank coals at a given mercury concentration. Eastern bituminous coals also tend to produce a greater proportion of flue gas mercury in the ionic or oxidized form (which is captured by scrubbers installed for sulfur control) than sub-bituminous coal, including coals produced in the Powder River Basin. High rank coals are also amenable to other methods of controlling mercury emissions, such as by powdered activated carbon injection. The EPA’s proposed control of mercury was recently vacated by a federal court requiring the EPA to develop a new proposal on mercury controls. Prior to federal court action, some states have already adopted a control program for mercury.
Production
In the year ended December 31, 2009, 91% of CONSOL Energy’s production came from underground mines and 9% from surface mines. Where the geology is favorable and reserves are sufficient, CONSOL Energy employs longwall mining systems in our underground mines. For the year ended December 31, 2009, 87% of our production came from mines equipped with longwall mining systems. Underground longwall systems are highly mechanized, capital intensive operations. Mines using longwall systems have a low variable cost structure compared with other types of mines and can achieve high productivity levels compared with those of other underground mining methods. Because CONSOL Energy has substantial reserves readily suitable to these operations, CONSOL Energy believes that these longwall mines can increase capacity at low incremental cost.
The following table shows the production, in millions of tons, for CONSOL Energy’s mines in the years ended December 31, 2009, 2008 and 2007, the location of each mine, the type of mine, the type of equipment used at each mine and the year each mine was established or acquired by us.
A= Auger
S = Surface
U = Underground
LW = Longwall
CM = Continuous Miner
S/L = Stripping Shovel and Front End Loaders
R = Rail
B = Barge
R/B = Rail to Barge
T = Truck
CB = Conveyor Belt
(1) Mine was idled for part of the year ended December 31, 2009 due to market conditions.
(2) Mine was idled throughout most of 2009 due to converting from track haulage, to more efficient belt haulage to remove coal from the mine.
(3) Harrison Resource Corporation, Miller Creek, Amvest Fola, Jones Fork and Mill Creek Complex include facilities operated by independent mining contractors.
(4) Production amounts represent CONSOL Energy’s 49% ownership interest.
(5) Mine Acquired in AMVEST Corporation acquisition on July 31, 2007.
(6) Buchanan Mine was idled for part of the year ended December 31, 2008 and part of the year ended December 31, 2007 after several roof falls in previously mined areas damaged some of the ventilation controls inside the mine.
(7) Mine was sold in February 2008.
Our sales of bituminous coal were at an average sales price per ton produced as follows:
Construction on a new slope, overland belt and underground belt haulage system at our Shoemaker Mine in West Virginia was completed. The mine began production using the entire system in mid-January 2010. Construction of a new slope and overland belt at the Bailey Mine in Pennsylvania continued during 2009. The project is expected to be complete by the end of March 2010. Both projects are expected to improve productivity, increase production, reduce costs and enhance safety. Modern conveyor systems typically provide high availability rates, thereby allowing mining equipment to produce at higher levels. Overland belts do not require the daily maintenance of the mine roof that underground haulage systems require allowing manpower to be reduced or redeployed to more productive work. Mine safety is expected to be enhanced by the overland belts because older underground belt areas will be sealed.
The Buchanan Mine preparation plant was upgraded. The upgrades included an increase in capacity, construction of a second raw coal silo and an upgrade of the conveyor belt system at the preparation plant. The project was completed in August and has performed as expected. Also, construction of a reverse osmosis water treatment system (RO) was started during 2009. The RO system will provide a constant water source to the Buchanan preparation plant and provide water needed in the underground coal production at the mine. Construction of the RO is expected to be completed in the third quarter of 2010.
Title to coal properties that we lease or purchase and the boundaries of these properties are verified at the time we lease or acquire the properties by law firms retained by us. Consistent with industry practice, abstracts and title reports are reviewed and updated approximately five years prior to planned development or mining of the property. If defects in title or boundaries of undeveloped reserves are discovered in the future, control of and the right to mine reserves could be adversely affected.
The following table sets forth, with respect to properties that we lease to other coal operators, the total royalty tonnage, acreage leased and the amount of income (net of related expenses) we received from royalty payments for the years ended December 31, 2009, 2008 and 2007.
Royalty tonnage leased to third parties is not included in the amounts of produced tons that we report. Proven and probable reserves do not include reserves attributable to properties that we lease to third parties.
The following table ranks the 20 largest underground mines in the United States by tons of coal produced in calendar year 2008.
MAJOR U.S. UNDERGROUND COAL MINES-2008
In millions of tons
Source: National Mining Association
Marketing and Sales
We sell coal produced by our mining complexes and additional coal that is purchased by us for resale from other producers. We maintain United States sales offices in Atlanta, Philadelphia and Pittsburgh. In addition, we sell coal through agents and to brokers and unaffiliated trading companies. In 2009, we sold 58.1 million tons of coal, including our portion of equity affiliates. Eighty-eight percent (88%) of these sales were sold in domestic markets. Our direct sales to domestic electricity generators represented 83% of our total tons sold in 2009. We had approximately 90 customers in 2009. During 2009, no coal customers individually accounted for more than 10% of total revenue. However, the top four coal customers accounted for more than 25% of our total revenues.
Coal Contracts
We sell coal to customers under arrangements that are the result of both bidding procedures and unsolicited offers leading to extensive negotiations. We sell coal for terms that range from a single shipment to multi-year agreements for millions of tons. During the year ended December 31, 2009, approximately 90% of the coal we produced was sold under contracts with terms of one year or more. The pricing mechanisms under our multiple-year agreements typically consist of contracts with one or more of the following pricing mechanisms:
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Fixed price contracts with pre-established prices; or
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Periodically negotiated prices that reflect market conditions at the time or are restricted to an agreed upon percentage increase or decrease; or
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Base-price-plus-escalation methods which allow for periodic price adjustments based on inflation indices.
Several contracts provide the opportunity to periodically adjust the contract prices. Contract prices may be adjusted as often as quarterly based upon indices which are pre-negotiated. Most of our contracts have terms no longer than five years. However, some of our contracts range in term from seven years to twenty years.
The following table sets forth, as of January 20, 2010, the total tons of coal CONSOL Energy is committed to deliver from 2010 through 2014.
* 2010 Tons committed and priced include 3.1 million tons of metalurgical coal at a price of $96.00 per ton.
We routinely engage in efforts to renew or extend contracts scheduled to expire. Although there are no guarantees, we generally have been successful in renewing or extending contracts in the past.
Contracts also typically contain force majeure provisions allowing for the suspension of performance by the customer or us for the duration of specified events beyond the control of the affected party, including labor disputes and extraordinary geological conditions. Some contracts may terminate upon continuance of an event of force majeure for an extended period, which is generally three to twelve months. Contracts also typically specify minimum and maximum quality specifications regarding the coal to be delivered. Failure to meet these conditions could result in price reductions, damages, suspension of deliveries or termination of the contract, at the election of the customer. Although the volume to be delivered under a long-term contract is stipulated, we or the buyer may vary the timing of delivery within specified limits.
Distribution
Coal is transported from CONSOL Energy’s mining complexes to customers by means of railroad cars, river barges, trucks, conveyor belts or a combination of these means of transportation. We employ transportation specialists who negotiate freight and equipment agreements with various transportation suppliers, including railroads, barge lines, terminal operators, ocean vessel brokers and trucking companies for certain customers. Most customers negotiate their own freight contracts.
At December 31, 2009 we operated 24 towboats, 5 harbor boats and a fleet of more than 650 barges that serve customers along the Ohio, Allegheny, Kanawha and Monongahela Rivers. The barge operation allows us to control delivery schedules and has served as temporary floating storage for coal when land storage is unavailable.
Competition
The United States coal industry is highly competitive, with numerous producers selling into all markets that use coal. CONSOL Energy competes against other large producers and hundreds of small producers in the United States and overseas. The five largest producers are estimated by the 2008 National Mining Association Survey to have produced approximately 53% (based on tonnage produced) of the total United States production in 2008. The U.S. Department of Energy reported 1,435 active coal mines in the United States in 2008, the latest year for which government statistics are available. Demand for our coal by our principal customers is affected by:
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the price of competing coal and alternative fuel supplies, including nuclear, natural gas, oil and renewable energy sources, such as hydroelectric power;
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coal quality;
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transportation costs from the mine to the customer; and
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the reliability of fuel supply.
Continued demand for CONSOL Energy’s coal and the prices that CONSOL Energy obtains are affected by demand for electricity, environmental and government regulation, technological developments and the availability and price of competing coal and alternative fuel supplies. We sell coal to foreign electricity generators and to the more specialized metallurgical coal market, both of which are significantly affected by international demand and competition.
Gas Operations
Our gas operations are primarily conducted by CNX Gas Corporation (CNX Gas), an 83.3% owned subsidiary of CONSOL Energy. Information presented below is 100% of CNX Gas’ basis; it does not include 16.7% noncontrolling interest reduction. CNX Gas primarily produces coalbed methane, which is gas that resides in coal seams. In the eastern United States, conventional natural gas fields typically are located in various types of sedimentary formations at depths ranging from 2,000 to 15,000 feet. Exploration companies often put their capital at risk by searching for gas in commercially exploitable quantities at these depths. By contrast, gas in the coal seams that we drill or anticipate drilling is typically in formations less than 2,500 feet deep which are usually better defined than deeper formations. CNX Gas believes that this contributes to lower exploration costs than those incurred by producers that operate in deeper, less defined formations. However, we have continued to increase our exploratory efforts in the shale and deeper formations.
CNX Gas has not filed reserve estimates with any federal agency.
Areas of Operation
In the Appalachian Basin we operate principally in Central Appalachia and Northern Appalachia. We also operate in the Illinois Basin. Our primary operating areas are:
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Central Appalachia, Virginia Operations coalbed methane (CBM), in Southwest Virginia, our traditional and largest area of operation, where we have typically produced CBM from vertical wells which we drill ahead of mining and gob gas wells;
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Northern Appalachia, Mountaineer CBM in northwestern West Virginia and southwestern Pennsylvania where we drill vertical-to-horizontal CBM wells;
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Northern Appalachia, Nittany CBM in central Pennsylvania, where we drill vertical CBM wells;
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Northern Appalachia, Mountaineer-Conventional, in northwest West Virginia and southwest Pennsylvania, where we continue development in the Marcellus Shale and shallow conventional zones;
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Northern Appalachia, Buckeye-Conventional in southeastern and central Ohio where we have begun drilling vertical exploration wells in the Marcellus and shallow conventional zones;
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Tennessee, Knox-Chattanooga Shale, in eastern Tennessee, where we intend to convert our horizontal exploration program in the Chattanooga Shale into a full scale development program; and
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Illinois Basin, Cardinal, in western Kentucky, Indiana and Illinois, where we are conducting an exploration program in the New Albany Shale and shallow oil zones.
In addition to the above areas, we believe we have Appalachian shale potential in the Huron shale. Additional potential exists in the Trenton Black River formation which is thought to underlie nearly all of the Appalachian shales. We will continue to evaluate our acreage position in these areas with the continuation of our exploration program.
Central Appalachia
Virginia Operations CBM
We have the rights to extract CBM in this region from approximately 405,000 net CBM acres, which cover a portion of our coal reserves in Central Appalachia. We produce gas primarily from the Pocahontas #3 seam which is the main coal seam mined by our Buchanan Mine. This seam is generally found at depths of 2,000 feet and generally ranges from 3 to 6 feet thick. The gas content of this seam is typically between 400 and 600 cubic feet of gas per ton of coal in place. In addition, there are as many as 50 thinner seams present in the several hundred feet above the main Pocahontas #3 seam. Collectively, this series of coal seams represents a total thickness ranging from 15 to 40 feet. We have access to over 1,300 core holes that allow us to determine the amount of coal present, the geologic structure of the coal seam and the gas content of the coal.
We coordinate some of our CBM extraction with the subsurface coal mining of our Buchanan Mine. The initial phase of CBM extraction involves drilling a traditional vertical wellbore into the coal seam in advance of future mining activities. In general, we drill these wells into the coal seam ahead of the planned coal mining recovery in an area. To stimulate the flow of CBM to the wellbore, we fracture the coal seam by pumping water or inert gases into the coal seam. Once established, these fractures are maintained by further forcing sand into the fractures to keep them from closing, allowing CBM to desorb from the coal and migrate along the series of fractures into the wellbore. We refer to this type of well as a “frac well.” In 2009, frac wells account for approximately 76% of our Virginia production.
Because some of our gas is produced in association with subsurface mining, we have a unique opportunity to evaluate the effectiveness of our fracture techniques. We can enter the coal mine and inspect the fracture pattern created in the seam as the mining process exposes more of the coal. As a result, we have had the opportunity to gain insight into the efficiency of our fracturing techniques that is not available in a conventional production scenario. We have used this knowledge to modify and improve the effectiveness of our fracturing techniques.
Eventually, subsurface mining activities will mine through the frac wells that are drilled in advance of the mine development plan. As the main coal seam is removed from an area (called a “panel”), a rubble zone (called “gob”) is formed in the cavity created by the extraction of the coal. When the coal is removed, the rock above collapses into the void. These upper seams become extensively fractured and release substantial volumes of gas. We drill vertical wells (called “gob wells”) into the gob to extract the additional gas that is released. Approximately 10% of our 2009 Virginia gas production came from gob gas from active coal operations.
We also drill long horizontal wellbores into the coal seam from within active mines. We strategically locate these horizontal wells within the pattern of existing frac wells to further accelerate the desorption of CBM from the coal seam. We have drilled 15 of these “in-mine” horizontal wells, some of which have been extended to lengths of 5,000 feet. These wells show that a more efficient recovery of gas in place is possible ahead of mining operations. In-mine horizontal wells accounted for approximately 1% of Virginia production in 2009.
Virginia Operations Shale and Tight Sands
We have 224,000 net acres of Huron shale potential in Kentucky and Virginia; a portion of this acreage has tight sands potential.
Tennessee
The Chattanooga Shale in Tennessee is a Devonian-age shale found at a depth of approximately 3,500 feet. Shale thickness is between 40-80 feet, but CNX Gas has found it to be rich in total organic content. CNX Gas has 269,000 net acres of Chattanooga Shale. This largely contiguous acreage is composed of only a small number of leases, a rarity in Appalachia. CNX Gas is the operator of all of its Chattanooga Shale wells. CNX Gas believes that we drilled the first successful horizontal Chattanooga Shale well and that we have currently drilled more horizontal wells than any other operator in this play.
Northern Appalachia
Mountaineer CBM
We have the right to extract CBM in this region from approximately 799,000 net CBM acres, which contain most of our recoverable coal reserves in Northern Appalachia. We produce gas primarily from the Pittsburgh #8 coal seam. This seam is generally found at depths of less than 1,000 feet and generally ranges from 4 to 7 feet thick. The gas content of this seam is typically between 100 and 250 cubic feet of gas per ton of coal in place. There are additional coal seams above and below the Pittsburgh #8 seam. Collectively, this series of coal seams represents a total thickness ranging from 10 to 30 feet. We have access to nearly 8,000 data points that allow us to determine the amount of coal present, the geologic structure of the coal seam and the gas content of the coal.
Due to the significant geological differences between the Pittsburgh #8 seam in Mountaineer and the Pocahontas #3 seam in Virginia, we have found that alternative extraction techniques are more effective than vertical frac wells in this area. Instead of using frac wells, we utilize well designs that rely on the application of vertical-to-horizontal drilling techniques. This well design includes a vertical wellbore that is intersected by a second well that has up to four horizontal lateral sections in the coal. Together, this well system facilitates extraction of CBM and water from the coal seam. The horizontal wellbores, extending up to 5,000 feet from the point of intersection with the vertical wellbore, expose large amounts of coal surface area allowing for the migration of water and CBM from the coal seam. The wells are spaced on approximately 480 acre sections. The vertical well, equipped with a mechanical pump, provides a sump for water produced by the coal seam to collect and enables the collected water to be lifted to the surface for disposal. In addition to our vertical-to-horizontal drilling, we also develop gob wells in this region associated with our coal mines.
Nittany CBM
We have the right to extract CBM in this region of Pennsylvania from approximately 260,000 net CBM acres, which contain most of our recoverable coal reserves as well as significant leases from other coal owners.
Marcellus Shale
We have substantially increased our acreage position in the Marcellus Shale from 186,000 net acres at December 31, 2008 to 250,000 net acres at December 31, 2009. We also have 161,000 net acres of shallow conventional potential in Ohio, Pennsylvania, West Virginia, and New York. In 2009, CNX Gas drilled and completed fourteen wells in the Marcellus Shale in southwestern Pennsylvania. Three wells were completed as vertical completions and the remaining eleven wells were drilled and completed as horizontal wells. All wells were turned into production as of December 31, 2009.
Shallow Oil and Gas
In 2009, CNX Gas drilled and completed six shallow conventional wells and drilled one shallow conventional well to total depth in south central Pennsylvania. Two additional shallow conventional wells were drilled and completed in eastern Ohio. Eight of the nine total wells are in production at December 31, 2009 while the remaining well is awaiting completion of gathering facilities for collection.
Others
Cardinal Shale
We control approximately 338,000 net acres of rights to gas in the New Albany shale in Kentucky, Illinois, and Indiana. The New Albany shale is a formation containing gaseous hydrocarbons, and our acreage position has thickness of 50-300 feet at an average depth of 2,500-4000 feet. In 2009, we continued testing the New Albany Shale which will lead us to drilling two horizontal wells in early 2010. We also have identified shallow oil and gas in which we produce two additional wells.
Illinois Basin CBM
We also control 515,000 net CBM acres in Illinois and Indiana, including 71,000 net CBM acres which contain most of our recoverable coal reserves in Illinois.
Other Acreage
We have the right to extract CBM on 139,000 net acres in the San Juan Basin, 20,000 net acres in the Powder River Basin, 41,000 net acres in eastern Ohio, and 51,000 net acres in central West Virginia. We also have the right to extract oil and gas on 12,000 net acres in the San Juan Basin, 10,000 net acres in the Powder River Basin, and 40,000 net acres in various other areas.
Summary of Properties as of December 31, 2009
(1) Includes areas leased to others or participation interests in third party wells, as well as small acreage in other areas.
Development Wells (Net)
During the years ended December 31, 2009, 2008 and 2007, we drilled 247, 534 and 370 net development wells, respectively. Gob wells and wells drilled by other operators that we participate in are excluded. There was one dry development well in 2009. There were no dry development wells in 2008 or 2007. As of December 31, 2009, six wells are still in process. The following table illustrates the wells drilled referenced above by geographic region:
Exploratory Wells (Net)
During the year ended December 31, 2009, 2008 and 2007, we drilled in the aggregate 18, 56 and 9 net exploratory wells, respectively. As of December 31, 2009, ten wells are still in process. The following table illustrates the exploratory wells drilled referenced above by geographic region:
Summary of Other Operating Data
Production
The following table sets forth net sales volumes produced for the periods indicated. There was no production from equity affiliates for the years ended December 31, 2009 and 2008. The year ended December 31, 2007 included our portion of equity interests.
Average Sales Prices and Lifting Costs
The following table sets forth the average sales price and the average lifting cost (the year ended December 31, 2007 includes our portion of equity interests) for all of our gas production for the periods indicated, including intersegment transactions. Lifting cost is the cost of raising gas to the gathering system and does not include depreciation, depletion or amortization.
Productive Wells and Acreage
Most of our development wells and proved acreage are located in Central Appalachia. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments are satisfied. The following table sets forth, at December 31, 2009, the number of CNX Gas producing wells, developed acreage and undeveloped acreage:
(1) Net acres do not include acreage attributable to the working interests of our principal joint venture partners and the portions of certain proved developed acreage attributable to property we have leased to third-party producers. Additional adjustments (either increases or decreases) may be required as we further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable.
We enter into physical gas sales transactions with various counterparties for terms varying in length. Reserves and production estimates are believed to be sufficient to satisfy these obligations. In the past, other than interstate pipeline outages related to maintenance issues or a weather related force majeure event, we have not failed to deliver quantities required under contract. We also entered into various gas swap transactions that qualify as financial cash flow hedges. These gas swap transactions exist parallel to the underlying physical transactions and represented approximately 51.6 billion cubic feet of our produced gas sales volumes for the year ended December 31, 2009 at an average price of $8.76 per thousand cubic feet. As of December 31, 2009, we expect these transactions will cover approximately 45.7 billion cubic feet of our estimated 2010 production at an average price of $7.88 per thousand cubic feet, 22.6 billion cubic feet of our estimated 2011 production at an average price of $6.84 and 15.1 billion cubic feet of our estimated 2012 production at an average price of $6.84.
We have purchased firm transportation capacity on various interstate pipelines to ensure gas production flows to market. As of December 31, 2009, we have secured firm transportation capacity to cover more than our 2010, 2011 and 2012 hedged production.
The hedging strategy and information regarding derivative instruments used are outlined in “Management’s Discussion and Analysis of Results of Operations and Financial Condition-Qualitative and Quantitative Disclosures About Market Risk” and in Note 23 to the Consolidated Financial Statements.
Reserves
The following table shows our estimated proved developed and proved undeveloped reserves. Reserve information is net of royalty interest. Proved developed and proved undeveloped reserves are reserves that could be commercially recovered under current economic conditions, operating methods and government regulations. Proved developed and proved undeveloped reserves are defined by the Securities and Exchange Commission (SEC).
Discounted Future Net Cash Flows
The following table shows our estimated future net cash flows and total standardized measure of discounted future net cash flows at 10%:
(1) We calculate our present value at 10% (PV-10) in accordance with the following table. Management believes that the presentation of the non-Generally Accepted Accounting Principle (GAAP) financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes estimated to be paid, the use of a pre-tax measure is valuable when comparing companies based on reserves. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation to the most directly comparable GAAP measure-after-tax discounted future net cash flows.
Reconciliation of PV-10 to Standardized Measure
Competition
We operate primarily in the eastern United States. We believe that the gas market is highly fragmented and not dominated by any single producer. We believe that several of our competitors have devoted far greater resources than we have to gas exploration and development. We believe that competition within our market is based primarily on gas commodity trading fundamentals and pipeline transportation availability to the diverse market opportunities.
Power Generation
Through a joint venture with Allegheny Energy Supply Company, LLC, an affiliate of one of our largest coal customers, CNX Gas owns a 50% interest in an 88-megawatt, gas-fired electric generating facility. This facility is used for meeting peak load demands for electricity. The facility is located in southwest Virginia and
uses coalbed methane gas that we produce. Because it is a peaking power facility, it does not operate at all times of the year, but the facility does provide a potential sales outlet for CNX Gas of up to 22 million cubic feet per day.
Other
CONSOL Energy provides other services both to our own operations and to others. These include land services, industrial supply services, terminal services (including break bulk, general cargo and warehouse services), river and dock services, and coal waste disposal services.
Land Resources
CONSOL Energy is developing property assets previously used to support our coal operations or property assets currently not utilized. CONSOL Energy expects to increase the value of our property assets by:
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developing surface properties for commercial uses other than coal mining or gas development when the location of the property is suitable;
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deriving royalty income from coal, oil and gas reserves CONSOL Energy owns but does not intend to develop;
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deriving income from the sustainable harvesting of timber on land CONSOL Energy and CNX Gas owns; and
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deriving income from the rental of surface property for agricultural and non-agricultural uses.
CONSOL Energy’s objective is to improve the return on these assets without detracting from our core businesses and without significant additional capital investment.
Industrial Supply Services
Fairmont Supply Company, a CONSOL Energy subsidiary, is a general-line distributor of mining and industrial supplies in the United States. Fairmont Supply has 28 customer service centers nationwide. Fairmont Supply also provides integrated supply procurement and management services. Integrated supply procurement is a materials management strategy that utilizes a single, full-line distribution to minimize total cost in the maintenance, repair and operating supply chain.
Fairmont Supply provides mine supplies to CONSOL Energy’s mining and gas operations. Approximately 44% of Fairmont Supply’s sales in 2009 were made to CONSOL Energy and CNX Gas’ operations.
Fairmont Supply Company’s 100% owned subsidiary, Piping and Equipment, is a specialty distributor of pipe, valve and fittings. Piping and Equipment has ten locations in Florida, Alabama, Louisiana and Texas. Fairmont Supply Company’s other 100% owned subsidiary, North Penn Pipe & Supply, LLC has locations in Warren and Troy, Pennsylvania, and distributes oil and gas field products, primarily tubular goods to the Northern Appalachia basin.
Terminal Services
In 2009, approximately 6.4 million tons of coal were shipped through CONSOL Energy’s subsidiary, CNX Marine Terminal Inc.’s, exporting terminal in the Port of Baltimore. Approximately 45% of the tonnage shipped was produced by CONSOL Energy coal mines. The terminal can either store coal or load coal directly into vessels from rail cars. It is also one of the few terminals in the United States served by two railroads, Norfolk Southern and CSX Transportation, Inc.
River and Dock Services
CONSOL Energy’s river operations, located in Monessen, Pennsylvania, transports coal from our mines, coal from other mines and non-coal commodities from river loadout facilities primarily along the Monongahela and Ohio Rivers in northern West Virginia and southwestern Pennsylvania. Products are delivered to customers along the Monongahela, Ohio, Kanawha and Allegheny rivers. At December 31, 2009, we operated 24 towboats, 5 harbor boats and more than 650 barges. In 2009, our river vessels transported a total of 17.3 million tons of coal and other commodities, including 6.1 million tons of coal produced by CONSOL Energy mines.
CONSOL Energy provides dock services for our mines as well for third parties at our Alicia Dock, located on the Monongahela River in Fayette County, Pennsylvania. CONSOL Energy transfers coal from rail cars to barges for customers that receive coal on the river system.
Coal Waste Disposal Services
CONSOL Energy operates an ash disposal facility on a 61-acre site in northern West Virginia to handle ash residues for coal customers that are unable to dispose of ash on-site at their generating facilities. The ash disposal facility can process 200 tons of material per hour, and is expected to dispose of approximately 125 thousand tons of fly ash in the current contract year. CONSOL Energy has a long-term contract with a cogeneration facility to supply coal and take the residual fly ash and bottom ash. Bottom ash is disposed locally at the cogeneration facility for road construction and other purposes.
Employee and Labor Relations
At December 31, 2009, CONSOL Energy had 8,012 employees, approximately 34.5% of whom were represented by the United Mine Workers of America (UMWA). A five-year labor agreement commenced January 1, 2007. This agreement expires December 31, 2011 and provides for a 20% across-the-board wage increase over its duration. Wages increased $0.50 per hour in 2009, and will increase $0.50 per hour for 2010 through 2011. Other terms of the agreement require additional contributions to be made into the employee benefit funds. Full health-care benefits for active and retired members and their dependents continued with no increase in co-payments. Newly employed inexperienced employees represented by the UMWA, hired after January 1, 2007 will not be eligible to receive retiree health care benefits. In lieu of these benefits, these employees will receive a defined contribution benefit of $1 per each hour worked.
Laws and Regulations
The coal mining and gas industries are subject to regulation by federal, state and local authorities on matters such as the discharge of materials into the environment, employee health and safety, permitting and other licensing requirements, reclamation and restoration of properties after mining or gas operations are completed, management of materials generated by mining and gas operations, surface subsidence from underground mining, water discharge effluent limits, water appropriation, legislatively mandated benefits for current and retired coal miners, air quality standards, protection of wetlands, endangered plant and wildlife protection, limitations on land use, storage of petroleum products and substances that are regarded as hazardous under applicable laws, and management of electrical equipment containing polychlorinated biphenyls, or PCBs. In addition, the electric power generation industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for CONSOL Energy’s coal and gas products. The possibility exists that new legislation or regulations may be adopted which would have a significant impact on CONSOL Energy’s mining or gas operations or our customers’ ability to use coal or gas and may require CONSOL Energy or our customers to change their operations significantly or incur substantial costs.
Numerous governmental permits and approvals are required for mining and gas operations. Regulations provide that a mining permit or modification can be delayed, refused or revoked if an officer, director or a stockholder with a 10% or greater interest in the entity is affiliated with or is in a position to control another
entity that has outstanding permit violations. Thus, past or ongoing violations of federal and state mining laws by individuals or companies no longer affiliated with CONSOL Energy could provide a basis to revoke existing permits and to deny the issuance of additional permits. CONSOL Energy is, or may be, required to prepare and present to federal, state or local authorities data and/or analyses pertaining to the effect or impact that any proposed exploration for or production of coal or gas may have upon the environment, public and employee health and safety. All requirements imposed by such authorities may be costly and time-consuming and may delay commencement or continuation of exploration or production operations. Accordingly, the permits we need for our mining and gas operations may not be issued, or, if issued, may not be issued in a timely fashion. Permits we need may involve requirements that may be changed or interpreted in a manner which restricts our ability to conduct our mining and gas operations or to do so profitably. Future legislation and administrative regulations may increasingly emphasize the protection of the environment and employee health and safety. As a consequence, the activities of CONSOL Energy may be more closely regulated. Such legislation and regulations, as well as future interpretations of existing laws, may require substantial increases in equipment and operating costs to CONSOL Energy and delays, interruptions or a termination of operations, the extent of which cannot be predicted.
While it is not possible to quantify the expenditures we incur to maintain compliance with all applicable federal and state laws, those costs have been and are expected to continue to be significant. We post surety performance bonds or letters of credit pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closing, often including the cost of treating mine water discharge when necessary. Compliance with these laws has substantially increased the cost of coal mining and gas production for all domestic coal and gas producers. We also post performance bonds or letters of credit pursuant to state oil and gas laws and regulations to guarantee reclamation of gas well sites and plugging of gas wells. We endeavor to conduct our mining and gas operations in compliance with all applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining and gas operations occur from time to time. None of the violations to date, or the monetary penalties assessed have been material. CONSOL Energy made capital expenditures for environmental control facilities of approximately $50.4 million, $10.6 million and $17.6 million in the years ended December 31, 2009, 2008 and 2007, respectively. The capital expenditures for environmental control facilities increased in 2009 primarily due to starting construction of a water processing system at Buchanan Mine. CONSOL Energy expects to have capital expenditures of $39.0 million for 2010 for environmental control facilities.
Mine Health and Safety Laws
Legislative and regulatory changes have required us to purchase additional safety equipment, construct stronger seals to isolate mined out areas, and engage in additional training. We have also experienced more aggressive inspection protocols resulting in the issuance of more citations and with new regulations the amount of fines have increased.
The actions taken thus far by federal and state governments include requiring:
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the caching of additional supplies of self-contained self rescuer (SCSR) devices underground;
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the purchase and installation of electronic communication and personal tracking devices underground;
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the placement of rescue chambers, which are structures designed to provide refuge for groups of miners during a mine emergency when evacuation from the mine is not possible, which will provide breathable air for 96 hours;
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the reconstruction of existing seals in worked-out areas of mines;
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the purchase of new fire resistant conveyor belting underground; and
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additional training and testing that creates the need to hire additional employees.
Black Lung Legislation
Under federal black lung benefits legislation, each coal mine operator is required to make payments of black lung benefits or contributions to:
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current and former coal miners totally disabled from black lung disease;
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certain survivors of a miner who dies from black lung disease or pneumoconiosis; and
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a trust fund for the payment of benefits and medical expenses to claimants whose last mine employment was before January 1, 1970, where no responsible coal mine operator has been identified for claims (where a miner’s last coal employment was after December 31, 1969), or where the responsible coal mine operator has defaulted on the payment of such benefits. The trust fund is funded by an excise tax on U.S. production of up to $1.10 per ton for deep mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.
The Affordable Health Choices Act currently being debated in the U.S. legislature provides for significant changes to the current Federal Black Lung Program. The current proposed legislative language would:
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provide for an automatic survivor benefit to be paid upon the death of a miner with an awarded black lung claim without proving that death was due to coal workers’ pneumoconiosis; and
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establish a rebuttable presumption if a miner had 15 or more years of coal mine employment and they were totally disabled by a respiratory condition that;
1. the miner is totally disabled due to pneumoconiosis;
2. that the miners death was due to pneumoconiosis;
3. or that at the time of death the miner was totally disabled by pneumoconiosis; and
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be retroactive to claims filed or pending since 2005.
The proposed legislation could have a material impact on the cost of our Federal Black Lung Program. The impact of the proposed changes is dependent upon what is finally approved by the legislature.
In addition to the federal legislation, we are also liable under various state statutes for black lung claims.
Retiree Health Benefits Legislation
The Coal Industry Retiree Health Benefit Act of 1992 (the Act) established the Combined Benefit Fund (the Combined Fund). The Combined Fund provides medical and death benefits for all beneficiaries including orphan retirees of the former United Mine Workers of America (UMWA) Benefit Trusts who were actually receiving benefits as of July 20, 1992. The Act also created a second benefit fund for UMWA retirees, the 1992 Benefit Plan. The 1992 Benefit Fund principally provides medical and death benefits to orphan UMWA-represented members eligible for retirement on February 1, 1993, and who actually retired between July 20, 1992 and September 30, 1994. The Act provides for the assignment of beneficiaries to former signatory employers or related companies and the allocation of unassigned beneficiaries (referred to as orphans) to the companies. The task of calculating the annual per beneficiary premium that assigned operators are obligated to pay to the Combined Fund is the responsibility of the Commissioner of Social Security.
The UMWA 1993 Benefit Plan is a defined contribution plan that was created as the result of negotiations for the National Bituminous Coal Wage Agreement (NBCWA) of 1993. This plan provides health care benefits to orphan UMWA retirees who are not eligible to participate in the Combined Fund, the 1992 Benefit Fund, or whose last employer signed the 1993 or later NBCWA, and who subsequently goes out of business.
The Act requires some of our subsidiaries to make premium payments to the Combined Fund and to the 1992 Benefit Plan for the cost of our retirees and orphan retirees in the Combined Fund and the 1992 Benefit Plan. In addition, the NBCWA of 2007 requires our signatory subsidiaries to make specified payments to the
1993 Benefit Plan through 2011. The Tax Relief and Health Care Act of 2006 (the 2006 Act) provides additional federal funding for these orphan costs by authorizing general fund revenues and expanding transfers of interest from the Abandoned Mine Land (AML) trust fund. The additional federal funding, depending upon its magnitude and the amount of orphan benefits payable, should cover the orphan premium payments due under the Combined Fund as well as, after a phase-in period, the orphan premium payments due under the 1992 Benefit Plan. The 1992 Benefit Plan has a phase-in period for the federal contributions. Federal contributions were 25% in 2008 and 50% in 2009. Federal contributions will be 75% in 2010 and 100% thereafter. In addition, federal contributions are also to be phased-in over these same periods with respect to the costs for those orphan retirees as of December 31, 2006 under the 1993 Benefit Plan. Under the 2006 Act, these general fund contributions to the Combined Fund, the 1992 Benefit Plan, the 1993 Benefit Plan and certain Abandoned Mine Land payments to the states and Indian tribes are collectively limited by an aggregate annual cap of $490 million. These federal contributions do not apply to our subsidiaries’ assigned retired miners, and therefore our subsidiaries will continue to make premium payments for our assigned retired miners who receive benefits from the Combined Fund, the 1992 Benefit Plan and for certain beneficiaries of the 1993 Benefit Plan. In addition, our subsidiaries remain responsible for making orphan premium payments to these plans to the extent that the federal contributions are not sufficient to cover the benefits.
Pension Protection Act
The Pension Protection Act of 2006 (the Pension Act) has simplified and transformed rules governing the funding of defined benefit plans, accelerated funding obligations of employers, made permanent certain provisions of the Economic Growth and Tax Relief Reconciliation Act of 2001 (EGTRRA), made permanent the diversification rights and investment education provisions for plan participants and encourages automatic enrollment in defined contribution 401(k) plans. In general, most provisions of the Pension Act of 2006 are in effect for plan years beginning on or after December 31, 2008. Plans generally are required to set a funding target of 100% of the present value of accrued benefits and sponsors are required to amortize unfunded liabilities over a 7-year period. The Pension Act includes a funding target phase-in provision consisting of a 94% funding target in 2009, 96% in 2010 and 100% thereafter. Plans with a funded ratio of less than 80%, or less than 70% using special assumptions, will be deemed to be “at risk” and will be subject to additional funding requirements. The 2009 plan year funding ratio was 113%. The funding ratio is subject to year over year volatility and Internal Revenue Service’s calculation guidelines.
Environmental Laws
CONSOL Energy is subject to various federal environmental laws, including:
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the Surface Mining Control and Reclamation Act of 1977,
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the Clean Air Act,
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the Clean Water Act,
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the Toxic Substances Control Act,
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the Endangered Species Act,
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the Comprehensive Environmental Response, Compensation and Liability Act,
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the Emergency Planning and Community Right to Know Act, and
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the Resource Conservation and Recovery Act
as administered and enforced by United States Environmental Protection Agency (EPA) and/or authorized federal or state agencies, as well as state laws of similar scope, and other state environmental and conservation laws in each state in which CONSOL Energy operates.
These environmental laws require reporting, permitting and/or approval of many aspects of coal mining and gas operations. Both federal and state inspectors regularly visit mines and other facilities to ensure compliance. CONSOL Energy has ongoing compliance and permitting programs designed to ensure compliance with such environmental laws.
Given the retroactive nature of certain environmental laws, CONSOL Energy has incurred and may in the future incur liabilities in connection with properties and facilities currently or previously owned or operated as well as sites to which CONSOL Energy or our subsidiaries sent waste materials.
Surface Mining Control and Reclamation Act
The Surface Mining Control and Reclamation Act (“SMCRA”) establishes minimum national operational, reclamation and closure standards for all surface mines as well as most aspects of deep mines. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and following completion of mining activities. Permits for all mining operations must be obtained from the Federal Office of Surface Mining Reclamation and Enforcement (“OSM”) or, where state regulatory agencies have adopted federally approved state programs under SMCRA, the appropriate state regulatory authority. States that operate federally approved state programs may impose standards which are more stringent than the requirements of SMCRA and OSM’s regulations and in many instances have done so. All states in which CONSOL Energy’s active mining operations are located have achieved primary jurisdiction for enforcement of SMCRA through approved state programs.
SMCRA permit provisions include requirements for coal exploration; baseline environmental data collection and analysis; 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; refuse disposal plans; surface drainage control; mine drainage and mine discharge control and treatment; and site reclamation. The mining permit application process, whether state or federal, 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 and wildlife, and 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 we will mine. We develop mine and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. The mine and reclamation plan incorporates the provisions of SMCRA, the state programs and the complementary environmental programs that impact coal mining. Detailed engineering plans are included for all surface facilities built as part of the mine, including roads, ponds, shafts and slopes, boreholes, portals, pipelines and power lines, excess spoil disposal areas and coal refuse disposal facilities. Also included in the permit application are documents defining corporate ownership and control, property ownership and agreements pertaining to coal, minerals, oil and gas, water rights, rights of way and surface land and documents required by the OSM Applicant Violator System. We also must list all public and privately-owned structures located within minimum defined distances near to or above our mines and mining facilities. Once a permit application is prepared and submitted to the regulatory agency, it goes through an administrative completeness review and a separate technical review. Public notice of the proposed permit application is given in a local newspaper followed by a public comment period before a permit can be issued. Some mining permits take over a year to prepare, depending on the size and complexity of the mine and can take six months to three years to be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance. The public has the right to comment on and otherwise participate in the permitting process, including through administrative appeals of permits and possibly further appeals in the courts. The mine operator must submit a bond or otherwise secure the performance of reclamation obligations, including, as deemed appropriate by the regulatory authority, a bond sufficient to cover the costs of long-term treatment of mine drainage discharges from closed facilities or ones from which a post-mining discharge is anticipated. The earliest a reclamation bond can be fully released is five years after reclamation has been completed, however, partial releases may be obtained as certain stages of reclamation are completed. All states impose on mine operators the responsibility for repairing or compensating for damage occurring on the surface as a result of mine subsidence, a possible consequence of longwall or other methods of underground mining, including an obligation to restore or replace domestic water supplies adversely affected by underground mining. All states also impose an obligation on surface mining operations to replace domestic, agricultural or industrial water supplies adversely affected by such operations. In addition, SMCRA imposes a reclamation fee on all current mining operations, the proceeds of which are deposited in the Abandoned Mine
Reclamation Fund (AML Fund), which is used to restore unreclaimed and abandoned mine lands mined before 1977. The per ton fee is $0.315 for surface mined coal and $0.135 per ton for underground mined coal. From October 1, 2012 through September 30, 2021, the fees will be $0.28 per ton for surface mined coal and $0.12 per ton for underground mined coal.
Under SMCRA, responsibility for unabated violations of SMCRA and other specified “environmental laws,” unpaid civil penalties and unpaid reclamation fees of subsidiaries and affiliates can be imputed to the “parents” and “related companies” if deemed to be “owned or controlled” by such entities. Data describing such ownership links must be provided by CONSOL Energy to the regulatory authorities. Similar “violations” by independent contract mine operators can also be imputed to other companies which are deemed, according to the regulations, to have “owned” or “controlled” the contract mine operator. Sanctions against the “owner” or “controller” are quite severe and can include being blocked from receiving new permits and revocation of any permits that have been issued since the time of the violations or, in the case of civil penalties and reclamation fees, since the time such amounts became due.
In the Commonwealth of Pennsylvania, where CONSOL Energy operates four longwall mines, approximately $10.3 million and $8.3 million of expenses were incurred during the years ended December 31, 2009 and 2008, respectively, to mitigate and repair impacts on streams from subsidence. Interpretations of technical guidance documents related to impacts of longwall mining on Pennsylvania streams require additional analysis on stream flows and biological statistics. We have received violation notices for past longwall activities which resulted in lower stream flows and water pooling areas both of which we are in the process of remediating. We also are completing additional stream analysis in order to comply with these recent interpretations at current Pennsylvania mining operations. Future Pennsylvania Department of Environmental Protection enforcement actions could cause CONSOL Energy to change mine plans, to incur significant costs, and potentially even shut down mines in order to meet compliance requirements. We currently estimate expenses related to subsidence of streams in Pennsylvania will be approximately $23.9 million for the year ended December 31, 2010.
Clean Air Act and Related Regulations
The federal Clean Air Act and similar state laws and regulations which regulate emissions into the air, affect coal mining, coal handling and processing, and gas processing operations primarily through permitting and/or emissions control requirements. For example, regulations relating to fugitive dust and coal combustion emissions could restrict CONSOL Energy’s ability to develop new mines or require CONSOL Energy to modify our operations. National Ambient Air Quality Standards (“NAAQS”) for particulate matter resulted in some areas of the country being classified as non-attainment for fine particulate matter. Because thermal dryers located at coal preparation plants burn coal and emit particulate matter, CONSOL Energy’s mining operations are likely to be directly affected where the NAAQS are implemented by the states.
CONSOL Energy believes we have obtained all necessary permits under the Clean Air Act. These permits have various expiration dates through March 2015. CONSOL Energy monitors permits required by operations regularly and takes appropriate action to extend or obtain permits as needed.
The Clean Air Act also indirectly affects coal mining operations by extensively regulating the air emissions of the coal fired electric power generating plants operated by our customers. Coal contains impurities, such as sulfur, mercury and other constituents, many of which are released into the air when coal is burned. Environmental regulations governing emissions from coal-fired electric generating plants could affect demand for coal as a fuel source and affect the volume of our sales. For example, the federal Clean Air Act places limits on sulfur dioxide, nitrogen dioxide, and mercury emissions from electric power plants.
In October 1998, the EPA finalized a rule requiring a number of eastern U.S. states to make substantial reductions in nitrogen oxide emissions by June 1, 2004 (the NOX SIP call). Further sulfur dioxide and nitrogen oxide emission reductions were adopted by regulations called the Clean Air Interstate Rules (“CAIR”), which were promulgated by the EPA in 2005. In July and December 2008, the U.S. Court of Appeals for the District of Columbia remanded the CAIR regulations to EPA but did not vacate the regulations. The regulations were not vacated because many states were already implementing them and some coal fired electric generating facilities were being equipped with scrubbers in order to comply with the CAIR requirements. EPA’s position is that the CAIR rules are in effect and the states must implement them. EPA intends to adopt replacement regulations, but there is no specific schedule in place. The installation of additional control measures to achieve these reductions makes it more costly to operate coal-fired power plants and could make coal a less attractive fuel. In order to meet the proposed new limits for sulfur dioxide emissions from electric power plants, many coal users 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 low sulfur coal or other fuels. More strict emission limits mean few coals can be burned without the installation of supplemental environmental control technology in the form of scrubbers. Many of our customers are in the process of installing scrubbers in response to the CAIR emissions requirements. We estimate that by 2012, more than half of the installed, coal-fired power plant capacity east of the Mississippi will be scrubbed. The increase in scrubbed capacity allows customers to consider purchasing more of our higher sulfur coals.
In 2005, the EPA finalized the Clean Air Mercury Rule (“CAMR”) which imposed caps on mercury emissions from coal-fired electric generating units. The first phase of the emission caps would have taken effect in 2010. In February 2008, the U.S. Court of Appeals for the D.C. Circuit vacated the CAMR. EPA has indicated that it will develop emission limits for mercury for coal fired electric generating facilities under Section 112 of the Clean Air Act, which requires EPA to impose maximum achievable control technology limits. In October 2008, New York and the New England states submitted a petition to EPA under the Clean Water Act requesting EPA to convene a conference to address contributions of airborne mercury emissions that upwind states are alleged to be making to downwind water quality. This petition appears to be aimed at coal fired power plants. Various states have promulgated or are considering more stringent emission limits on mercury emissions from coal-fired electric generating units. Regulation of mercury emissions from coal-fired electric generating units could impact the market for coal.
A regional haze program initiated by the EPA to protect and to improve visibility at and around national parks, national wilderness areas and international parks may restrict the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas and may require some existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions. These requirements could limit the demand for coal in some locations.
The United States Department of Justice, on behalf of the EPA, has filed lawsuits against several investor-owned electric utilities and brought an administrative action against one government-owned utility for alleged violations of the Clean Air Act. These lawsuits could require the utilities to pay penalties, install pollution control equipment or undertake other emission reduction measures which could positively or negatively impact their demand for CONSOL Energy coal. One such suit was settled in October 2007, by the owner of sixteen coal fueled electric generating plants located in Indiana, Kentucky, Ohio, Virginia and West Virginia. Although the utility did not admit any violations of the Clean Air Act, it agreed to annual sulfur dioxide and nitrogen oxides emission limits for all of its plants and it agreed to install additional emission controls on two of its plants.
Also, numerous proposals have been made at the international, national, regional and state levels that are intended to limit or capture emissions of greenhouse gases, such as carbon dioxide, and several states have adopted measures intended to reduce greenhouse gas loading in the atmosphere. If comprehensive legislation focusing on greenhouse gas emissions is enacted by the United States or individual states, it may adversely affect the use of and demand for fossil fuels, particularly coal, as an energy source for electricity generation. The U.S. Congress is considering climate change legislation that proposes to restrict greenhouse gas (GHG) emissions. President Obama
has pledged to implement an economy-wide cap-and-trade program to reduce GHG emissions 80 percent by 2050 and pledged that he would cause the United States to be a world leader on GHG reduction and re-engage with the United Nations Framework Convention on Climate Change to develop a global GHG program. In 2007, the U.S. Supreme Court held in Massachusetts v. Environmental Protection Agency (EPA), that the EPA had authority to regulate GHGs under the Clean Air Act and a number of states have filed lawsuits seeking to force the EPA to adopt GHG regulations. In December 2009, the EPA made a determination that GHGs cause or contribute to air pollution and may reasonably be anticipated to endanger public health or welfare, which findings are prerequisites to EPA regulating GHGs under the Clean Air Act. Moreover, several states have already adopted, and other states are considering the adoption of, legislation or regulations to reduce emissions of greenhouse gases. Such regulation would significantly increase the cost of generation of electricity at coal fired facilities and could make competing forms of electricity generation more competitive.
Clean Water Act
The federal Clean Water Act and corresponding state laws affect coal mining and gas operations by imposing restrictions on discharges into regulated surface waters. Permits requiring regular monitoring and compliance with effluent limitations and reporting requirements govern the discharge of pollutants into regulated waters. The Clean Water Act and corresponding state laws include requirements for: protection of “impaired waters” so designated by individual states through the use of new effluent limitations known as Total Maximum Daily Load (“TMDL”) limits; anti-degradation regulations which protect state designated “high quality/exceptional use” streams by restricting or prohibiting discharges which result in degradation; requirements to treat discharges from coal mining properties for non-traditional pollutants, such as chlorides, selenium and dissolved solids; and “protecting” streams, wetlands, other regulated water sources and associated riparian lands from surface mining and/or the surface impacts of underground mining. These requirements may cause CONSOL Energy to incur significant additional costs that could adversely affect our operating results, financial condition and cash flows.
Permits for discharges of fill material into streams in connection with mining operations are issued by the Army Corps of Engineers (the “COE”). The COE is empowered to issue “nationwide” permits for specific categories of filing activity that are determined to have minimal environmental adverse effects in order to save the cost and time of issuing individual permits under Section 404 of the Clean Water Act. Individual permits are required for activities determined to have more significant impacts to waters of the United States. Nationwide Permit 21 authorizes the disposal of dredge-and-fill material from mining activities into the waters of the United States. Since 2003, environmental groups have pursued litigation primarily in West Virginia and Kentucky challenging the validity of Nationwide Permit 21 and various individual permits authorizing valley fills associated with surface coal mining operations (primarily mountain top removal operations). This litigation has resulted in delays in obtaining these permits and has increased permitting costs. The most recent major decision in this line of litigation is the opinion of the United States Court of Appeals for the Fourth Circuit in Ohio Valley Environmental Council v. Aracoma Coal Company, 556 F.3d 177 (2009) (Aracoma), issued on February 13, 2009. Aracoma appeared to be a major victory for the coal industry because the Court rejected all of the substantive challenges to the Section 404 permits involved in the case primarily by deferring to the expertise of the COE in review of the permit applications. The effect of the Aracoma decision was quickly nullified by several EPA initiatives. First, in early 2009, the EPA began to comment on Section 404 permit applications pending before the COE raising many of the same issues decided in favor of the coal industry in Aracoma. Many of the EPA’s comment letters were submitted long after the end of the EPA’s comment period based on what the EPA contended was “new” information on the impacts of valley fills on stream water quality immediately downstream of valley fills. However, the comment letters addressed many issues beyond the “new” information on alleged water quality impacts, such as, minimization of the size and number of valley fills, cumulative impacts of the operation on the watershed, and the types and extent of mitigation. These comment letters practically resulted in a moratorium on the issuance of Section 404 permits for valley fills for coal surface mines. A second initiative of the EPA is “enhanced” review of any permit for a coal mining activity that requires both a SMCRA permit and a Section 404 permit in the states of Kentucky, Ohio, Pennsylvania, Tennessee, Virginia and West
Virginia (designated as “Appalachian surface coal mining”). This initiative resulted in a joint Memorandum of Understanding (MOU) among the COE, the EPA and the Department of Interior (OSM). The “enhanced” review under the MOU has continued the delay in COE action on pending Section 404 permit applications. The EPA’s third initiative is to take a more active role in its review of NPDES permit applications for coal mining operations; especially in West Virginia where the EPA has decided to review all such NPDES permit applications. All of these initiatives have resulted in delays in the review and issuance of permits for surface coal mining applications. We anticipate that it will take longer to obtain permits and the costs of obtaining permits and compliance with permit conditions will increase significantly. So far, CONSOL Energy subsidiaries have been able to continue operating their existing mines. Also, in 2009 one subsidiary was able to obtain a Section 404 permit for a new surface mine in southern West Virginia. However, the new permit contains EPA mandated environmental protection conditions. Additionally, on January 4, 2010, the EPA published a notice in the Federal Register seeking public comment on the EPA’s enforcement and compliance priorities for fiscal years 2011 through 2013. The list of priorities includes energy/mining resource extraction (a new priority targeting mountain top removal mining).
A CONSOL Energy subsidiary is subject to a state administrative order in West Virginia that requires compliance in 2013 with effluent limits for chlorides for discharges from four active and two closed underground coal mines in northern West Virginia. Given the volumes of water involved and the options that are available to timely meet the effluent limits, it is likely that it will be necessary to construct one or more treatment facilities using advanced water treatment technologies. These requirements may cause CONSOL Energy to incur additional costs that could adversely affect our operating results, financial condition and cash flows.
Comprehensive Environmental Response, Compensation and Liability Act (Superfund)
The Comprehensive Environmental Response, Compensation and Liability Act (Superfund) and similar state laws create liabilities for the investigation and remediation of releases of hazardous substances into the environment and for damages to natural resources. Our current and former coal mining operations incur, and will continue to incur, expenditures associated with the investigation and remediation of facilities and environmental conditions, including underground storage tanks, solid and hazardous waste disposal and other matters under Superfund and similar state environmental laws. We also must comply with reporting requirements under the Emergency Planning and Community Right-to-Know Act and the Toxic Substances Control Act.
From time to time, we have been the subject of administrative proceedings, litigation and investigations relating to sites that have releases of hazardous substances. We have been in the past and currently are named as a potentially responsible party at Superfund sites. We may become involved in future proceedings, litigation or investigations and incur liabilities that could be materially adverse to us.
Resource Conservation and Recovery Act
The federal Resource Conservation and Recovery Act (RCRA) and corresponding state laws and regulations affect coal mining and gas operations by imposing requirements for the treatment, storage and disposal of hazardous wastes. Facilities at which hazardous wastes have been treated, stored or disposed are subject to corrective action orders issued by the EPA which could adversely affect our results, financial condition and cash flows.
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, such as coal ash. In May 2000, the EPA concluded that coal combustion wastes do not warrant regulation as hazardous under RCRA resulting in coal combustion wastes remaining exempt from hazardous waste regulation. However, the EPA determined that national non-hazardous waste regulations under RCRA are needed for coal combustion wastes disposed in surface
impoundments and landfills and used as mine-fill, and the Office of Surface Mining is currently developing these regulations. The agency also concluded that beneficial uses of these wastes, other than for mine-filling, pose no significant risk and no additional national regulations are needed. Most state hazardous waste laws also exempt coal combustion waste, and instead treat it as either a solid waste or a special waste. In response to the Tennessee Valley Authority coal ash spill in December 2008, the EPA initiated a fast-track regulatory process in which it is considering three possible regulatory scenarios for coal combustion wastes: regulation as a non-hazardous waste under Subtitle D of RCRA, regulation as a hazardous waste under Subtitle C, or a hybrid Subtitle C/D approach. Industry and state regulatory agencies are trying to convince the EPA that the states are adequately regulating handling and disposal of coal combustion wastes. The loss of the hazardous waste exemption for coal combustion waste, or the adoption of new regulations for disposing of coal combustion waste which impose significant additional costs, could adversely affect the demand for coal for electricity generation.
Federal Coal Leasing Amendments Act
Mining operations on federal lands in the western United States are affected by regulations of the United States Department of the Interior. The Federal Coal Leasing Amendments Act of 1976 amended the Mineral Lands Leasing Act of 1920 which authorized the leasing of federal coal lands for coal mining. The Federal Coal Leasing Amendments Act increased the royalties payable to the United States Government for federal coal leases and required diligent development and continuous operations of leased reserves within a specified period of time. Subtitle D of the Energy Policy Act of 2005 (Pub. L. 109-58) contained the Coal Leasing Amendments Act of 2005, which includes provisions designed to facilitate efficient and economic development of federal coal leases. The United States Department of the Interior has stated that it intends to promulgate new regulations and implement these 2005 amendments. Regulations adopted by the United States Department of the Interior to implement such legislation could affect coal mining by CONSOL Energy from federal coal leases for operations developed that would incorporate such leases. Currently, CONSOL Energy’s only active operation with federal coal leases is the Emery Mine.
Endangered Species Act
The Federal Endangered Species Act (ESA) and similar state laws protect species threatened with extinction. Protection of endangered species may affect our ability to obtain permits, may delay issuance of mining permits, or may cause us to modify mining plans to avoid or minimize impacts to endangered species or their habitats. A number of species indigenous to the areas where we operate are protected under the ESA. Based on the species that have been identified and the current application of applicable laws and regulations, we do not believe that there are any species protected under the ESA or state laws that would materially and adversely affect our ability to mine coal from our properties.
Federal Regulation of the Sale and Transportation of Gas
Various aspects of our gas operations are regulated by agencies of the federal government. The Federal Energy Regulatory Commission regulates the transportation and sale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. While “first sales” by producers of natural gas, and all sales of condensate and natural gas liquids can be made currently at uncontrolled market prices, Congress could reenact price controls in the future. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.
Regulations and orders set forth by the Federal Energy Regulatory Commission also impact our gas business to a certain degree. Although the Federal Energy Regulatory Commission does not directly regulate our gas production activities, the Federal Energy Regulatory Commission has stated that it intends for certain of its orders to foster increased competition within all phases of the natural gas industry. Additionally, the Federal Energy Regulatory Commission continues to review its transportation regulations, including whether to allocate
all short-term capacity on the basis of competitive auctions and whether changes to its long-term transportation policies may also be appropriate to avoid a market bias toward short-term contracts. Additional Federal Energy Regulatory Commission orders have been adopted based on this review with the goal of increasing competition for natural gas markets and transportation.
The Federal Energy Regulatory Commission has also issued numerous orders confirming the sale and abandonment of natural gas gathering facilities previously owned by interstate pipelines and acknowledging that if the Federal Energy Regulatory Commission does not have jurisdiction over services provided by these facilities, then such facilities and services may be subject to regulation by state authorities in accordance with state law. In addition, the Federal Energy Regulatory Commission’s approval of transfers of previously-regulated gathering systems to independent or pipeline affiliated gathering companies that are not subject to Federal Energy Regulatory Commission regulation may affect competition for gathering or natural gas marketing services in areas served by those systems and thus may affect both the costs and the nature of gathering services that will be available to interested producers or shippers in the future.
We own certain natural gas pipeline facilities that we believe meet the traditional tests which the Federal Energy Regulatory Commission has used to establish a pipeline’s status as a gatherer not subject to the Federal Energy Regulatory Commission jurisdiction.
Additional proposals and proceedings that might affect the gas industry may be pending before Congress, the Federal Energy Regulatory Commission, the Minerals Management Service, state commissions and the courts. We cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. There is no assurance that the regulatory approach currently pursued by various agencies will continue indefinitely. Notwithstanding the foregoing, we do not anticipate that compliance with existing federal, state and local laws, rules and regulations will have a material or significantly adverse effect upon the capital expenditures, earnings or competitive position of CONSOL Energy or its subsidiaries. No material portion of our business is subject to renegotiation of profits or termination of contracts or subcontracts at the election of the federal government.
State Regulation of Gas Operations
Our operations are also subject to regulation at the state and in some cases, county, municipal and local governmental levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, the disposal of fluids used in connection with operations, and gas operations producing coalbed methane in relation to active mining. Our operations are also subject to various conservation laws and regulations. These include regulations that affect the size of drilling and spacing units or proration units, the density of wells which may be drilled and the unitization or pooling of gas properties. In addition, state conservation laws establish maximum rates of production from gas wells, generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production. A number of states have either enacted new laws or may be considering the adequacy of existing laws affecting gathering rates and/or services. Other state regulation of gathering facilities generally includes various safety, environmental and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Thus, natural gas gathering may receive greater regulatory scrutiny of state agencies in the future. Our gathering operations could be adversely affected should they be subject in the future to increased state regulation of rates or services, although we do not believe that they would be affected by such regulation any differently than other natural gas producers or gatherers. However, these regulatory burdens may affect profitability, and we are unable to predict the future cost or impact of complying with such regulations.
Ownership of Mineral Rights
The majority of our drilling operations are conducted on properties related to our coal holdings.
CONSOL Energy’s past practice has been to acquire ownership or leasehold rights to our coal properties prior to conducting our coal mining operations. Given CONSOL Energy’s long history as a coal producer we believe we have a well-developed ownership position relating to our coal holdings. Although CONSOL Energy generally attempts to obtain ownership or leasehold rights to CBM and/or conventional gas related to our coal holdings, our ownership position relating to these property estates is less developed. As is customary in the coal and gas industry, a summary review of the title to coal, CBM and other gas rights is made on properties at the time of the acquisition of the other rights in the properties. Prior to the commencement of gas drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties; we are typically responsible for curing any title defects. We generally will not commence our drilling operations on a property until we have cured any material title defects on such property. We completed title work on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the gas industry.
The following summary sets forth an analysis of provisions of Pennsylvania, Virginia and West Virginia law relating to the ownership of CBM. These summaries do not purport to be complete and are qualified in their entirety by reference to the provisions of applicable law and rights and the laws relating to traditional natural gas resources may differ materially from the rights related to CBM. These summaries are based on current law as of the date of this Annual Report.
Pennsylvania
In Pennsylvania, CBM that remains inside the coal seam is generally the property of the owner of that coal seam where the gas is located. CBM can be sold in place or leased by the coal owner to another party such as a producer who then would have the right to extract the gas from the coal seam under the terms of the agreement with the coal owner. Once the gas migrates from the coal into other strata, the coal owner no longer has clear title to that migrated gas. As a result, in certain circumstances in Pennsylvania (e.g., in a gob or mine void), we may be required to obtain other property interests (beyond ownership or leasehold interest in the coal rights or CBM) in order to extract gas that is no longer located in the coal seam.
Virginia
The vast majority of CBM we produce, as well as our proved reserves, are in Virginia. The Virginia Supreme Court has stated that the grant of coal rights only does not include rights to CBM absent an express grant of CBM, natural gases, or minerals in general. The situation may be different if there is any expression in the severance deed indicating more than mere coal is conveyed. Virginia courts have also found that the owner of the CBM did not have the right to fracture the coal in order to retrieve the CBM and that the coal operator had the right to ventilate the CBM in the course of mining. In Virginia, we believe that we control the relevant property rights in order to capture gas from the vast majority of our producing properties.
In addition, Virginia has established the Virginia Gas and Oil Board and a procedure for the development of CBM by an operator in those instances where the owner of the CBM has not leased it to the operator or in situations where there are conflicting claims of ownership of the CBM. The general practice is to force pool both the coal owner and the gas owner. In those instances, any royalties otherwise payable are paid into escrow and the burden then is upon the conflicting claimants to establish ownership by court action. The Virginia Gas and Oil Board does not make ownership decisions.
West Virginia
The West Virginia Supreme Court has held that in a conventional oil and gas lease executed prior to the inception of widespread public knowledge regarding CBM operations, the oil and gas lessee did not acquire the right to produce CBM. As of December 31, 2009, the West Virginia courts have not clarified who owns CBM in West Virginia. Therefore, the ownership of CBM is an open question in West Virginia.
West Virginia has enacted a law, the Coalbed Methane Wells and Units Act (the “West Virginia Act”), regulating the commercial recovery and marketing of CBM. Although the West Virginia Act does not specify who owns, or has the right to exploit, CBM in West Virginia and instead refers ownership disputes to judicial resolution, it contains provisions similar to Virginia’s pooling law. Under the pooling provisions of the West Virginia Act, an applicant who proposes to drill can prosecute an administrative proceeding with the West Virginia Coalbed Methane Review Board to obtain authority to produce CBM from pooled acreage. Owners and claimants of CBM interests who have not consented to the drilling are afforded certain elective forms of participation in the drilling (e.g., royalty or owner), but their consent is not required to obtain a pooling order authorizing the production of CBM by the operator within the boundaries of the drilling unit. The West Virginia Act also provides that, where title to subsurface minerals has been severed in such a way that title to coal and title to natural gas are vested in different persons, the operator of a CBM well permitted, drilled and completed under color of title to the CBM from either the coal seam owner or the natural gas owner has an affirmative defense to an action for willful trespass relating to the drilling and commercial production of CBM from that well.
We anticipate in future years to more actively explore for and develop Northern Appalachian CBM in West Virginia. As indicated, we may need or desire to acquire additional rights from other holders of real estate interests, including acquiring rights from other real estate interest holders if the law at that time continues to lack clarity on ownership rights to CBM in West Virginia. As we explore and develop this other acreage where we have coal rights, we expect in accordance with our existing procedures to have a title examination performed of the rights to CBM. If we believe we need to obtain additional rights from the holders of other real estate interests, we have developed a methodology as part of deciding the feasibility of developing a particular tract to evaluate the ability to locate and negotiate a royalty arrangement with those other holders or use pooling provisions under the West Virginia Act.
Other States
We have rights to extract CBM where we have coal rights in other states. The ownership of CBM in the Illinois Basin and certain other western basins may be uncertain or could belong to other holders of real estate interests and we may need to acquire additional rights from other holders of real estate interests to extract and produce CBM in these other states.
Available Information
CONSOL Energy maintains a website on the World Wide Web at www.consolenergy.com. CONSOL Energy makes available, free of charge, on this website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “1934 Act”), as soon as reasonably practicable after such reports are available, electronically filed with, or furnished to the SEC, and are also available at the SEC’s website www.sec.gov.
Executive Officers of the Registrant
Incorporated by reference into this Part I is the information set forth in Part III, Item 10 under the caption “Directors and Executive Officers of CONSOL Energy” (included herein pursuant to Item 401 (b) of Regulation S-K).
Item 1A.
Item 1A. Risk Factors.
Investment in our securities is subject to various risks, including risks and uncertainties inherent in our business. The following sets forth factors related to our business, operations, financial position or future financial performance or cash flows which could cause an investment in our securities to decline and result in a loss.
Continued weakness in global economic conditions or in any of the industries in which our customers operate, or sustained uncertainty in financial markets may have material adverse impacts on our business and financial condition that we currently cannot predict.
As widely reported, economic conditions in the United States and globally have deteriorated and the extent and timing of a recovery, especially in the United States and Europe, is uncertain. Financial markets in the United States, Europe and Asia have also experienced a period of unprecedented turmoil and upheaval characterized by extreme volatility and declines in security prices, severely diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse or sale of various financial institutions and an unprecedented level of intervention from the United States federal government and other governments. Unemployment has risen while business and consumer confidence have declined and there are fears of a prolonged recession in the United States and Europe. Although we cannot predict the impacts, continued weakness in the United States or global economies, in any of the industries we serve or in the financial markets could materially adversely affect our business and financial condition. For example:
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the demand for natural gas in the United States has declined and may remain at low levels or further decline if economic conditions remain weak and continue to negatively impact the revenues, margins and profitability of our natural gas business;
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the demand for electricity in the United States and for steel globally has declined and may remain at low levels or further decline if economic conditions remain weak and continue to negatively impact the revenues, margins and profitability of our steam and metallurgical coal businesses;
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the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables and the amount of receivables eligible for sale pursuant to our accounts receivable facility may decline;
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our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business including for exploration and/or development of our coal or gas reserves; and
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our commodity hedging arrangements could become ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection.
A significant or extended decline in the prices CONSOL Energy receives for our coal and gas could adversely affect our operating results and cash flows.
Our financial results are significantly affected by the prices we receive for our coal and gas. Extended or substantial price declines for coal would adversely affect our operating results for future periods and our ability to generate cash flows necessary to improve productivity and expand operations. Prices of coal may fluctuate due to factors beyond our control such as overall domestic and global economic conditions; the consumption pattern of industrial consumers, electricity generators and residential users; technological advances affecting energy consumption; domestic and foreign government regulations; price and availability of alternative fuels; price of foreign imports and weather conditions. Any adverse change in these factors could result in weaker demand and possibly lower prices for our production, which would reduce our revenues.
Gas prices are closely linked to consumption patterns of the electric generation industry and certain industrial and residential patterns where gas is the principal fuel. Natural gas prices are very volatile, and even relatively modest drops in prices can significantly affect our financial results and impede growth. Changes in natural gas prices have a significant impact on the value of our reserves and on our cash flow. In the past we have used hedging transactions to reduce our exposure to market price volatility when we deemed it appropriate. If we
choose not to engage in, or reduce our use of hedging arrangements in the future, we may be more adversely affected by changes in natural gas and oil prices than our competitors who engage in hedging arrangements to a greater extent than we do. Prices for natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as: the domestic and foreign supply of natural gas; the price of foreign imports; overall domestic and global economic conditions; the consumption pattern of industrial consumers, electricity generators and residential users; weather conditions; technological advances affecting energy consumption; domestic and foreign governmental regulations; proximity and capacity of gas pipelines and other transportation facilities; and the price and availability of alternative fuels. Many of these factors may be beyond our control. Lower natural gas prices may not only decrease our revenues on a per unit basis, but may also limit our access to capital. A significant decrease in price levels for an extended period would negatively affect us in several ways including our cash flow would be reduced, decreasing funds available for capital expenditures employed to replace reserves or increase production; and access to other sources of capital, such as equity or long-term debt markets, could be severely limited or unavailable. Additionally, lower natural gas prices may reduce the amount of natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our estimates of development costs increase, production data factors change or our exploration results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our natural gas properties. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management’s plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.
If customers do not extend existing contracts, do not honor existing contracts, or do not enter into new long-term contracts for coal, profitability of CONSOL Energy’s operations could be affected.
During the year ended December 31, 2009, approximately 91% of the coal CONSOL Energy produced was sold under long-term contracts (contracts with terms of one year or more). If a substantial portion of CONSOL Energy’s long-term contracts are modified or terminated or if force majeure is exercised, CONSOL Energy would be adversely affected if we are unable to replace the contracts or if new contracts are not at the same level of profitability. If existing customers do not honor current contract commitments, our revenue would be adversely affected. The profitability of our long-term coal supply contracts depends on a variety of factors, which vary from contract to contract and fluctuate during the contract term, including our production costs and other factors. Price changes, if any, provided in long-term supply contracts may not reflect our cost increases, and therefore, increases in our costs may reduce our profit margins. In addition, in periods of declining market prices, provisions for adjustment or renegotiation of prices and other provisions may increase our exposure to short-term coal price volatility. As a result, CONSOL Energy may not be able to obtain long-term agreements at favorable prices (compared to either market conditions, as they may change from time to time, or our cost structure) and long-term contracts may not contribute to our profitability.
The loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues.
For the year ended December 31, 2009, we derived over 25% of our total revenues from sales to our four largest coal customers. At December 31, 2009, we had approximately 16 coal supply agreements with these customers that expire at various times from 2010 to 2028. We are currently discussing the extension of existing agreements or entering into new long-term agreements with some of these customers, but these negotiations may not be successful and these customers may not continue to purchase coal from us under long-term coal supply agreements. If any one of these four 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.
Our ability to collect payments from our customers could be impaired if their creditworthiness declines or if they fail to honor their contracts with us.
Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. Some power plant owners may have credit ratings that are below investment grade. If the creditworthiness of our customers declines significantly, our $165 million accounts receivable securitization program and our business could be adversely affected. In addition, if a customer refuses to accept shipments of our coal for which they have an existing contractual obligation, our revenues will decrease and we may have to reduce production at our mines until our customer’s contractual obligations are honored.
The availability and reliability of transportation facilities and fluctuations in transportation costs could affect the demand for our coal or impair our ability to supply coal to our customers.
Coal producers depend upon rail, barge, trucking, overland conveyor and other systems to provide access to markets. Disruption of transportation services because of weather-related problems, strikes, lock-outs, break-downs of locks and dams or other events could temporarily impair our ability to supply coal to customers and adversely affect our profitability. Transportation costs represent a significant portion of the delivered cost of coal and, as a result, the cost of delivery is a critical factor in a customer’s purchasing decision. Increases in transportation costs could make our coal less competitive.
Competition within the coal and gas industries may adversely affect our ability to sell our products. A loss of our competitive position because of overcapacity in these industries could adversely affect pricing which could impair our profitability.
CONSOL Energy competes with coal producers in various regions of the United States and with some foreign coal producers for domestic sales primarily to power generators. CONSOL Energy also competes with both domestic and foreign coal producers for sales in international markets. Demand for our coal by our principal customers is affected by the delivered price of competing coals, other fuel supplies and alternative generating sources, including nuclear, natural gas, oil and renewable energy sources, such as hydroelectric power. CONSOL Energy sells coal to foreign electricity generators and to the more specialized metallurgical coal market, both of which are significantly affected by international demand and competition.
Increases in coal prices could encourage existing producers to expand capacity or for new producers to enter the market. If overcapacity results, prices could fall or we may not be able to sell our coal, which would reduce revenue.
The gas industry is intensely competitive with companies from various regions of the United States and we may compete with foreign companies for domestic sales, many of whom are larger and have greater financial, technological, human and other resources. If we are unable to compete, our company, our operating results and financial position may be adversely affected. For example, one of our competitive strengths is being a low-cost producer of gas. If our competitors can produce gas at a lower cost than us, it would effectively eliminate our competitive strength in that area. In addition, larger companies may be able to pay more to acquire new gas properties for future exploration, limiting our ability to replace gas we produce or to grow our production. Our ability to acquire additional properties and to discover new gas resources also depends on our ability to evaluate and select suitable properties and to consummate these transactions in a highly competitive environment.
We could be negatively affected if we fail to maintain satisfactory labor relations.
As of December 31, 2009, we had 8,012 employees. Approximately 35% of these employees are represented by unions. Union operations generated 46% of our U.S. coal production during the year ended December 31, 2009. Relations with our employees and, where applicable, organized labor is important to our success. If we do not maintain satisfactory labor relations with our organized and non-union employees, we may incur strikes, other work stoppages or have reduced productivity. Our labor costs may increase relative to other coal companies which could adversely affect our ability to compete with other coal companies and our results of operations.
The characteristics of coal may make it difficult for coal users to comply with various environmental standards. These standards are continually under review by international, federal and state agencies, related to coal combustion. As a result, coal users may switch to other alternative fuel or alternative energy sources, which would affect the volume of CONSOL Energy’s coal sales.
Coal contains impurities, including sulfur, mercury, chlorine and other elements or compounds, many of which are released into the air when coal is burned. Stricter environmental regulations of emissions from coal-fired electric generating plants could increase the costs of using coal thereby reducing demand for coal as a fuel source, the volume of our coal sales and price. Stricter regulations could make coal a less attractive fuel alternative in the planning and building of utility power plants in the future.
For example, in order to meet the federal Clean Air Act limits for sulfur dioxide emissions from electric power plants, coal users will need to install scrubbers, use sulfur dioxide emission allowances (some of which they may purchase), or switch to other fuels. Each option has limitations. Lower sulfur coal may be more costly to purchase on an energy basis than higher sulfur coal depending on mining and transportation costs. The cost of installing scrubbers is significant and emission allowances may become more expensive as their availability declines. Switching to other fuels may require expensive modification of existing plants. Because higher sulfur coal currently accounts for a significant portion of our sales, the extent to which power generators switch to alternative fuel could materially affect us if we cannot offset the cost of sulfur removal by lowering the delivered costs of our higher sulfur coals on an energy equivalent basis.
Proposed reductions in emissions of mercury, sulfur dioxides, nitrogen oxides, particulate matter or greenhouse gases may require the installation of additional costly control technology or the implementation of other measures, including trading of emission allowances and switching to alternative fuels. The Environmental Protection Agency continues to require reduction of nitrogen oxide emissions in a number of eastern states and the District of Columbia and will require reduction of particulate matter emissions over the next several years for areas that do not meet air quality standards for fine particulates. In addition, Congress and several states may consider legislation to further control air emissions of multiple pollutants from electric generating facilities and other large emitters. Any new or proposed reductions will make it more costly to operate coal-fired plants and could make coal a less attractive fuel alternative to the planning and building of utility power plants in the future. In addition, utilities may favor building new power plants fueled by natural gas because gas-fired plants are cheaper to construct and permits to construct these plants are easier to obtain as natural gas is seen as having a lower environmental impact than coal-fueled generators. Apart from alternative fuel sources, state and federal mandates for increased use of electricity from renewable energy sources could have an impact on the market for our coal. Several states have enacted legislative mandates requiring electricity suppliers to use renewable energy sources to generate a certain percentage of power. There have been numerous proposals to establish a similar uniform, national standard although none of these proposals have been enacted to date. Possible advances in technologies and incentives, such as tax credits, to enhance the economics of renewable energy sources could make these sources more competitive with coal. Any reduction in the amount of coal consumed by domestic
electric power generators as a result of new or proposed requirements or a switch to alternative fuels or renewable energy sources could reduce the price of coal that we mine and sell, thereby reducing our revenues and materially and adversely affecting our business and results of operations.
CONSOL Energy may not be able to produce sufficient amounts of coal to fulfill our customers’ requirements, which could harm our relationships with customers and could cause our inability to satisfy our contractual demands.
CONSOL Energy may not be able to produce sufficient amounts of coal to meet customer demand, including amounts that we are required to deliver under long-term contracts. CONSOL Energy’s inability to satisfy contractual obligations could result in our customers initiating claims against us.
Foreign currency fluctuations could adversely affect the competitiveness of our coal abroad.
We compete in international markets against coal produced in other countries. Coal is sold internationally in U.S. dollars. As a result, mining costs in competing producing countries may be reduced in U.S. dollar terms based on currency exchange rates, providing an advantage to foreign coal producers. Currency fluctuations among countries purchasing and selling coal could adversely affect the competitiveness of our coal in international markets.
Coal mining is subject to conditions or events beyond CONSOL Energy’s control, which could cause our financial results to deteriorate.
CONSOL Energy’s coal mining operations are predominantly underground mines. These mines are subject to conditions or events beyond CONSOL Energy’s control that could disrupt operations and affect production and the cost of mining at particular mines for varying lengths of time. These conditions or events may have a significant impact on our operating results. Conditions or events have included:
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variations in thickness of the layer, or seam, of coal;
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amounts of rock and other natural materials intruding into the coal seam and other geological conditions that could affect the stability of the roof and the side walls of the mine;
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equipment failures or repairs;
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fires and other accidents; and
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weather conditions.
A decrease in the availability or increase in the costs of key services, capital equipment or commodities such as steel, liquid fuels and rubber products could impact our cost of production and decrease our anticipated profitability.
Coal mines consume large quantities of key services, capital equipment and commodities (including steel, copper, rubber products and liquid fuels). Some commodities, such as steel, are needed to comply with roof control plans required by regulation. The prices we pay for these services and products are strongly impacted by the global market. A rapid or significant increase in their cost could impact our mining costs because we have a limited ability to negotiate lower prices, and, in some cases, do not have a ready substitute.
For mining and drilling operations, CONSOL Energy must obtain, maintain, and renew governmental permits and approvals which can be a costly and time consuming process and can result in restrictions on our operations.
Most producers in the eastern U.S. are being impacted by government regulations and enforcement to a much greater extent than a few years ago, particularly in light of the renewed focus by environmental agencies
and the government generally on the mining industry, including more stringent enforcement of the laws that regulate mining. The pace with which government issues permits needed for new operations and for on-going operations to continue mining has negatively impacted expected production, especially in Central Appalachia. Environmental groups in Southern West Virginia and Kentucky have challenged state and U.S. Army Corps of Engineers permits for mountaintop mining on various grounds. The most recent challenges have focused on the adequacy of the Corps of Engineers analysis of impacts to streams and the adequacy of mitigation plans to compensate for stream impacts resulting from valley fill permits required for mountaintop mining. In 2007, the U.S. District Court for the Southern District of West Virginia found other operators’ permits for mining in these areas to be deficient. In February 2009, the U.S. Court of Appeals for the Fourth Circuit reversed that decision, finding that the permits were adequate. However, since that reversal, the U.S. Environmental Protection Agency (EPA) began to more critically review valley fill permits and has been recommending that a number of permits be denied because of alleged concerns by EPA of potential impacts to water quality in streams below valley fills, with cumulative impacts of mining on watersheds and with adequacy of mitigation EPA’s objections and an enhanced review process that is being implemented under a federal multi-agency memorandum of understanding have effectively held up the issuance of permits for all types of mining operations that require valley fill permits, including surface facilities for underground mines, without any indication as to when normal permitting will resume. CONSOL Energy’s surface and underground operations have been impacted to a limited extent to date, but future permits will likely be delayed by the EPA’s current position, which will likely adversely impact our surface operations. In addition, over the past few years, the length of time needed to bring a new mine into production has increased by several years because of the increased time required to obtain necessary permits. New safety laws and regulations have impacted productivity at underground mines, although the company has not yet been able to ascertain the exact amount of the impact.
Proposals to regulate greenhouse gas emissions could impact the market for our fossil fuels, increase our costs and reduce the value of our coal and gas assets.
Global climate change continues to attract considerable public and scientific attention with widespread concern about the impacts of human activity, especially the emissions of greenhouse gases (GHGs), such as carbon dioxide and methane. Combustion of fossil fuels, such as the coal and gas we produce, results in the creation of carbon dioxide that is currently emitted into the atmosphere by coal and gas end users, such as coal-fired electric generation power plants. Numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government that are intended to limit emissions of GHGs. Several states have already adopted measures requiring reduction of GHGs within state boundaries. Further regulation of GHGs could occur in the United States pursuant to legislation, treaty obligations, regulation under the Clean Air Act, or states enacting new laws and regulations. Internationally, the Kyoto Protocol, which set binding emission targets for developed countries (including the United States but has not been ratified by the United States) expires in 2012 and negotiations are underway for a new protocol. In 2007, the U.S. Supreme Court upheld in Massachusetts v. the Environmental Protection Agency (EPA), that the EPA had authority to regulate GHG’s under the Clean Air Act and a number of states have filed lawsuits seeking to force the EPA to adopt GHG regulations. President Obama has pledged to implement an economy-wide cap-and-trade program to reduce GHG emissions 80 percent by 2050. He also pledged the United States to be a world leader on GHG reduction and re-engage with the United Nations Framework Convention on Climate Change to develop a global GHG program. Apart from governmental regulation, on February 4, 2008, three of Wall Street’s largest investment banks announced that they had adopted climate change guidelines for lenders. The guidelines require the evaluation of carbon risks in the financing of utility power plants which may make it more difficult for utilities to obtain financing for coal-fired plants. If comprehensive laws focusing on GHGs emission reductions were to be enacted by the United States, individual states, in other countries where we sell coal, or if utilities were to have difficulty obtaining financing in connection with coal-fired plants, it may adversely affect the use of and demand for fossil fuels, particularly coal, which could have a material adverse effect on our results of operations, cash flows and financial condition.
In July 2008, the EPA published an Advance Notice of Proposed Rulemaking (“ANPR”) seeking comments and discussion of the complex issues associated with the possible regulation of GHGs under the Clean Air Act.
The deadline for comments on the ANPR was November 28, 2008. The EPA sought comments and discussion on: (i) advantages and disadvantages of regulating GHGs under various provisions of the Clean Air Act; (ii) how a decision to regulate GHGs under one provision of the Clean Air Act would lead to regulation under other provisions; (iii) issues relevant to legislation to regulate greenhouse gases and the potential overlap of the Clean Air Act and such future legislation; and (iv) scientific information relevant to, and the issues raised by, an analysis as to whether greenhouse gas emissions from automobiles may reasonably be anticipated to endanger public health or welfare. In December 2009, the EPA made a determination that GHGs cause or contribute to air pollution and may reasonably be anticipated to endanger public health or welfare, which findings are prerequisites to the EPA regulating GHGs under the Clean Air Act.
Coalbed methane must be expelled from our underground coal mines for mining safety reasons. Coalbed methane enhances the GHG effect to a greater degree than carbon dioxide. Our gas operations capture coalbed methane from our underground coal mines, although some coalbed methane is vented into the atmosphere when the coal is mined. If regulation of GHG emissions does not exempt the release of coalbed methane, we may have to curtail coal production, pay higher taxes, or incur costs to purchase credits that permit us to continue operations as they now exist at our underground coal mines. The amount of coalbed methane we capture is recorded, on a voluntarily basis, with the U.S Department of Energy. We have recorded the amounts we have captured since the early 1990’s and our subsidiary, CNX Gas, has registered as an offset provider of credits with the Chicago Climate Exchange. If regulation of GHGs does not give us credit for capturing methane that would otherwise be released into the atmosphere at our coal mines, any value associated with our historical or future credits would be reduced or eliminated.
Existing and future government laws, regulations and other legal requirements relating to protection of the environment, health and safety matters and others that govern our business increase our costs of doing business for both coal and gas, and may restrict our operations.
We are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local, as well as foreign authorities relating to protection of the environment and health and safety matters, including those legal requirements that govern discharges of substances into the air and water, the management and disposal of hazardous substances and wastes, the cleanup of contaminated sites, groundwater quality and availability, plant and wildlife protection, reclamation and restoration of mining or drilling properties after mining or drilling is completed, the installation of various safety equipment in our mines, control of surface subsidence from underground mining and work practices related to employee health and safety. Complying with these requirements, including the terms of our permits, has had, and will continue to have, a significant effect on our costs of operations and competitive position. In addition, we could incur substantial costs as a result of violations under environmental and health and safety laws. Any additional laws, regulations and other legal requirements enacted or adopted by federal, state and local, as well as foreign authorities or new interpretations of existing legal requirements by regulatory bodies relating to the protection of the environment and health and safety matters could further affect our costs of operations and competitive position.
For example, the federal Clean Water Act and corresponding state laws affect coal mining and gas operations by imposing restrictions on discharges into regulated surface waters. Permits requiring regular monitoring and compliance with effluent limitations and reporting requirements govern the discharge of pollutants into regulated waters. The Clean Water Act and corresponding state laws (including those relating to protection of “impaired waters” so designated by individual states through the use of new effluent limitations known as Total Maximum Daily Load (“TMDL”) limits; anti-degradation regulations which protect state designated “high quality/exceptional use” streams by restricting or prohibiting “discharges” which result in degradation; and requirements to treat discharges from coal mining properties for non-traditional pollutants requiring expensive treatment technologies, such as total dissolved solids, chlorides and selenium; and “protecting” streams, wetlands, other regulated water sources and associated riparian lands from the surface impacts of underground mining) may cause CONSOL Energy to incur significant additional costs that could adversely affect our operating results, financial condition and
cash flows or may prevent us from being able to mine portions of our reserves. The Clean Water Act is being used by opponents of mountain top removal mining as a means to challenge permits. Also, beginning in early 2009, EPA has relied upon the Clean Water Act to become more actively involved in the permitting of mountain top removal mining operations and other coal mining operations requiring permits to place fill in streams. In addition, CONSOL Energy incurs and will continue to incur significant costs associated with the investigation and remediation of environmental contamination under the federal Comprehensive Environmental Response, Compensation, and Liability Act (Superfund) and similar state statutes and has been named as a potentially responsible party at Superfund sites in the past.
Additionally, the gas industry is subject to extensive legislation and regulation, which is under constant review for amendment or expansion. Any changes may affect, among other things, the pricing or marketing of gas production. State and local authorities regulate various aspects of gas drilling and production activities, including the drilling of wells (through permit and bonding requirements), the spacing of wells, the unitization or pooling of gas properties, environmental matters, safety standards, market sharing and well site restoration. If we fail to comply with statutes and regulations, we may be subject to substantial penalties, which would decrease our profitability.
Our mines are subject to stringent federal and state safety regulations that increase our cost of doing business at active operations and may place restrictions on our methods of operation. In addition, government inspectors under certain circumstances, have the ability to order our operations to be shut down based on safety considerations.
Stringent health and safety standards were imposed by federal legislation when the Federal Coal Mine Health and Safety Act of 1969 was adopted. The Federal Coal Mine Safety and Health Act of 1977 expanded the enforcement of safety and health standards of the Coal Mine Health and Safety Act of 1969 and imposed safety and health standards on all (non-coal as well as coal) mining operations. Regulations are comprehensive and affect numerous aspects of mining operations, including training of mine personnel, mining procedures, the equipment used in mine emergency procedures, mine plans and other matters. The additional requirements of the Mine Improvement and New Emergency Response Act of 2006 (the Miner Act) and implementing federal regulations include, among other things, expanded emergency response plans, providing additional quantities of breathable air for emergencies, installation of refuge chambers in underground coal mines, installation of two-way communications and tracking systems for underground coal mines, new standards for sealing mined out areas of underground coal mines, more available mine rescue teams and enhanced training for emergencies. Most states in which CONSOL Energy operates have programs for mine safety and health regulation and enforcement. We believe that the combination of federal and state safety and health regulations in the coal mining industry is, perhaps, the most comprehensive system for protection of employee safety and health affecting any industry. Most aspects of mine operations, particularly underground mine operations, are subject to extensive regulation. The various requirements mandated by law or regulation can place restrictions on our methods of operations, creating a significant effect on operating costs and productivity. In addition, government inspectors under certain circumstances, have the ability to order our operation to be shut down based on safety considerations.
CONSOL Energy has reclamation, mine closure and gas well plugging obligations. If the assumptions underlying our accruals are inaccurate, we could be required to expend greater amounts than anticipated.
The Surface Mining Control and Reclamation Act establishes operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining and gas well drilling. CONSOL Energy accrues for the costs of current mine disturbance, gas well plugging and of final mine closure, including the cost of treating mine water discharge where necessary. Estimates of our total reclamation, mine-closing liabilities and gas well plugging, which are based upon permit requirements and our experience, were approximately $533 million at December 31, 2009. The amounts recorded are dependent upon a number of variables, including the estimated future closure costs, estimated proven reserves, assumptions involving profit margins, inflation rates,
and the assumed credit-adjusted risk-free interest rates. Furthermore, these obligations are unfunded. If these accruals are insufficient or our liability in a particular year is greater than currently anticipated, our future operating results could be adversely affected.
CONSOL Energy faces uncertainties in estimating our economically recoverable coal reserves, and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability.
There are uncertainties inherent in estimating quantities and values of economically recoverable coal reserves, including many factors beyond our control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our staff.
Some of the factors and assumptions which impact economically recoverable reserve estimates include:
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geological conditions;
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historical production from the area compared with production from other producing areas;
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the assumed effects of regulations and taxes by governmental agencies;
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assumptions governing future prices; and
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future operating costs, including cost of materials.
Each of these factors may in fact vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of the economically recoverable quantities of coal attributable to a particular group of properties, and classifications of these reserves based on risk of recovery and estimates of future net cash flows, may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and these variances may be material. As a result, our estimates may not accurately reflect our actual reserves.
Fairmont Supply Company, a subsidiary of CONSOL Energy, is a co-defendant in various asbestos litigation cases which could result in making payments in the future that are material.
One of our subsidiaries, Fairmont Supply Company (Fairmont), which distributes industrial supplies, currently is named as a defendant in approximately 22,500 asbestos claims in state courts in Pennsylvania, Ohio, West Virginia, Maryland, Mississippi, New Jersey and Illinois. Because a very small percentage of products manufactured by third parties and supplied by Fairmont in the past may have contained asbestos and many of the pending claims are part of mass complaints filed by hundreds of plaintiffs against a hundred or more defendants, it has been difficult for Fairmont to determine how many of the cases actually involve valid claims or plaintiffs who were actually exposed to asbestos-containing products supplied by Fairmont. In addition, while Fairmont may be entitled to indemnity or contribution in certain jurisdictions from manufacturers of identified products, the availability of such indemnity or contribution is unclear at this time and, in recent years, some of the manufacturers named as defendants in these actions have sought protection from these claims under bankruptcy laws. Fairmont has no insurance coverage with respect to these asbestos cases. For the year ended December 31, 2009, payments by Fairmont with respect to asbestos cases have not been material. Our current estimates related to these asbestos claims, individually and in the aggregate, are immaterial to the financial position, results of operations and cash flows of CONSOL Energy. However, it is reasonably possible that payments in the future with respect to pending or future asbestos cases may be material to the financial position, results of operations or cash flows of CONSOL Energy.
CONSOL and its subsidiaries are subject to various legal proceedings, which may have a material effect on our business.
We are party to a number of legal proceedings incident to normal business activities. There is the potential that an individual matter or the aggregation of many matters could have an adverse effect on our cash flows,
results of operations or financial position. See Note 24 in the Notes to the Audited Consolidated Financial Statements in Item 8 of the Form 10-K for further discussion.
Changes in federal or state income tax regulations, particularly in the area of percentage depletion, could cause our financial position and profitability to deteriorate.
The federal government has been reviewing the income tax regulations relating to the coal industry regarding percentage depletion benefits. If the percentage depletion tax benefit was reduced or eliminated, CONSOL Energy’s financial position could be materially impacted.
CONSOL Energy has obligations for long-term employee benefits for which we accrue based upon assumptions which, if inaccurate, could result in CONSOL Energy being required to expense greater amounts than anticipated.
CONSOL Energy provides various long-term employee benefits to inactive and retired employees. We accrue amounts for these obligations. At December 31, 2009, the current and non-current portions of these obligations included:
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postretirement medical and life insurance ($2.8 billion);
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coal workers’ black lung benefits ($194.6 million);
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salaried retirement benefits ($192.0 million); and
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workers’ compensation ($179.3 million).
However, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated. Salary retirement benefits are funded in accordance with ERISA regulations. The other obligations are unfunded. In addition, the federal government and several states in which we operate consider changes in workers’ compensation and black lung laws from time to time. Such changes, if enacted, could increase our benefit expense.
Due to our participation in a multi-employer pension plan, we have exposure under that plan that extends beyond what our obligation would be with respect to our employees.
Certain of our subsidiaries are obligated to contribute to a multi-employer defined benefit pension plan for United Mine Workers of America (UMWA) retirees. In the event of a partial or complete withdrawal by us from such pension plan, we would be liable for a proportionate share of such pension plan’s unfunded vested benefits, as determined by the plan's actuary. Based on the limited information available from the plan's administrators, which we cannot independently validate, we believe that our portion of the contingent liability represented by the pension plan's unfunded vested benefits, in the case of our withdrawal from the pension plan or the termination of the pension plan, could be material to our financial position and results of operations. In the event that any other contributing employer withdraws from such pension plan and such employer (or any member in its controlled group) cannot satisfy their obligations under the plan at the time of withdrawal, then we, along with the other remaining contributing employers, would be liable for a proportionate share of the pension plan’s unfunded vested benefits at the time of our withdrawal from the pension plan or its termination.
The minimum funding level requirements of the Pension Protection Act of 2006 (Pension Act) applicable to single employer and multi-employer defined benefit pension plans, coupled with significant investment asset losses suffered by such pension plans during the recent decline in equity markets and the current volatile economic environment, have exposed CONSOL Energy to having to make additional cash contributions to fund the pension benefit plans which we sponsor and the multi-employer pension benefit plans in which we participate.
CONSOL Energy sponsors a defined benefit retirement plan that covers substantially all of our employees not participating in multi-employer pension plans. For this pension plan, the Pension Act requires a funding target of 100% of the present value of accrued benefits. The Pension Act includes a funding target phase-in provision that establishes a funding target of 96% in 2010 and 100% thereafter for our defined benefit pension plan. Any such plan with a funded ratio of less than 80%, or less than 70% using special assumptions, will be
deemed to be “at risk” and will be subject to additional funding requirements under the Pension Act. The volatile economic environment and the deterioration in the equity markets have caused investment income and the value of investment assets held in our pension trust to decline and lose value. As a result, CONSOL Energy may be required to increase the amount of cash contributions it makes into the pension trust in order to meet the funding level requirements of the Pension Act.
Certain subsidiaries of CONSOL Energy also participate in a defined benefit multi-employer pension plan negotiated with the UMWA and contained in the National Bituminous Coal Wage Agreement (the “NBCWA”). The NBCWA currently calls for contribution amounts to be paid into the multi-employer 1974 Pension Trust based principally on hours worked by UMWA-represented employees. The current contribution rates called for by the NBCWA are: $4.25 per hour worked in 2009, $5.00 per hour worked in 2010, and $5.50 per hour worked in 2011. These multi-employer pension plan contributions are expensed as incurred. The Pension Act requires a minimum funding ratio of 80% be maintained for this multi-employer pension plan. If the plan was determined to have a funded ratio of less than 80% it will be deemed to be “endangered” or "seriously endangered", and if less than 65%, it will be deemed to be in “critical” status, and will in either case be subject to additional funding requirements. Under the Pension Act, the multi-employer plan's actuary must certify the plan's funded status for each plan year. Based on an estimated funded percentage of 91.4%, a certification was provided by the multi-employer plan actuary, stating that the 1974 Pension Trust was in neither “endangered” nor “critical” status for the plan year beginning July 1, 2008. However, the volatile economic environment and the rapid deterioration in the equity markets caused investment income and the value of investment assets held in the 1974 Pension Trust to decline and lose value.
In late 2008, the Worker, Retiree and Employer Recovery Act of 2008 ("WRERA") was enacted. Under WRERA, a plan is permitted temporarily to avoid applying the Pension Act's requirements for improving its financial status by giving a plan the option to elect to retain its prior year zone status and to freeze the plan's zone status at the level determined for 2008. WRERA also required that the plan's actuary certify the plan's actual zone status for 2009. On September 28, 2009, based on an estimated funded percentage of 74%, the 1974 Pension Trust's actuary provided the Pension Act zone certification for 2009, certifying that the 1974 Pension Trust is “seriously endangered” for the plan year beginning July 1, 2009. Thereafter, pursuant to WRERA, the 1974 Pension Trust elected to retain its 2008 funded status of neither "endangered" nor “critical” for the plan year beginning July 1, 2009. If the freeze election had not been made, the 1974 Pension Trust's zone status for 2009 as certified by its actuary would have been "seriously endangered" and the 1974 Pension Trust would have been required to develop a funding improvement plan.
The freeze election only applies for the current plan year of 2009. If the 1974 Pension Trust is certified to be in endangered, seriously endangered or critical status for the plan year beginning July 1, 2010, steps will have to be taken under the Pension Act to improve its funded status. Such a determination would require certain subsidiaries of CONSOL Energy to make additional contributions pursuant to a funding improvement plan implemented in accordance with the Pension Act and, therefore, could have a material impact on our operating results.
If lump sum payments made to retiring salaried employees pursuant to CONSOL Energy’s defined benefit pension plan exceed the total of the service cost and the interest cost in a plan year, CONSOL Energy would need to make an adjustment to operating results equaling the unrecognized actuarial gain or loss resulting from each individual who received a lump sum payment in that year, which may result in an adjustment that could materially reduce operating results.
CONSOL Energy’s defined benefit pension plan for salaried employees allows such employees to receive a lump-sum distribution for benefits earned up through December 31, 2005 in lieu of annual payments when they retire from CONSOL Energy. Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans for Terminations Benefits requires that if the lump-sum distributions made for a plan year exceed the total of the service cost and interest cost for the plan year, CONSOL Energy would need to recognize for that year’s results
of operations an adjustment equaling the unrecognized actuarial gain or loss resulting from each individual who received a lump sum in that year. This type of adjustment may result in a material reduction in operating results.
Various federal or state laws and regulations require CONSOL Energy to obtain surety bonds or to provide other assurance of payment for certain of our long-term liabilities including mine closure or reclamation costs, workers’ compensation, coal workers’ black lung and other postemployment benefits.
Federal and state laws and regulations require us to provide surety bonds or provide other assurances to secure payment of certain long-term obligations including mine closure or reclamation costs, water treatment costs, federal and state workers’ compensation costs and other miscellaneous obligations. The requirements and amounts of security are not fixed and can vary from year to year. For certain requirements, there have been periods in the past when it has been difficult for us to secure new surety bonds or renew such bonds without posting collateral. CONSOL Energy has satisfied our obligations under these statutes and regulations by providing letters of credit or other assurances of payment. The issuance of letters of credit under our bank credit facility reduces amounts that we can borrow under our bank credit facility for other purposes.
Acquisitions that we have completed, acquisitions that we may undertake in the future, as well as expanding existing company mines involve a number of risks, any of which could cause us not to realize the anticipated benefits.
We have completed several acquisitions and mine and gas expansions in the past. We continually seek to grow our business by adding and developing coal and gas reserves through acquisitions; and by expanding the production at existing mines and existing gas operations. If we are unable to successfully integrate the companies, businesses or properties we acquire, our profitability may decline and we could experience a material adverse effect on our business, financial condition, or results of operations. Mine expansion, gas operation expansion and acquisition transactions involve various inherent risks, including:
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Uncertainties in assessing the value, strengths, and potential profitability of, and identifying the extent of all weaknesses, risks, contingent and other liabilities (including environmental liabilities) of expansion and acquisition opportunities;
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The potential loss of key customers, management and employees of an acquired business;
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The ability to achieve identified operating and financial synergies anticipated to result from an expansion or an acquisition opportunity;
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Problems that could arise from the integration of the acquired business; and
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Unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying our rationale for pursuing the expansion or the acquisition opportunity.
CONSOL Energy’s rights plan may have anti-takeover effects that could prevent a change of control.
On December 19, 2003, CONSOL Energy adopted a rights plan which, in certain circumstances, including a person or group acquiring, or the commencement of a tender or exchange offer that would result in a person or group acquiring, beneficial ownership of more than 15% of the outstanding shares of CONSOL Energy common stock, would entitle each right holder to receive, upon exercise of the right, shares of CONSOL Energy common stock having a value equal to twice the right exercise price. For example, at an exercise price of $80 per right, each right not otherwise voided would entitle its holders to purchase $160 worth of shares of CONSOL Energy common stock for $80. Assuming that shares of CONSOL Energy common stock had a per share value of $16 at such time, the holder of each right would be entitled to purchase ten shares of CONSOL Energy common stock for $80, or a price of $8 per share, one half its then market price. This and other provisions of CONSOL Energy’s rights plan could make it more difficult for a third party to acquire CONSOL Energy, which could hinder stockholders’ ability to receive a premium for CONSOL Energy stock over the prevailing market prices.
We face uncertainties in estimating proved recoverable gas reserves, and inaccuracies in our estimates could result in lower than expected reserve quantities and a lower present value of our reserves.
Natural gas reserves requires subjective estimates of underground accumulations of natural gas and assumptions concerning future natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be incorrect. Over time, material changes to reserve estimates may be made, taking into account the results of actual drilling, testing and production. Also, we make certain assumptions regarding future natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of our reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of gas we ultimately recover being different from reserve estimates.
The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on historical average prices and costs. However, actual future net cash flows from our gas and oil properties also will be affected by factors such as:
•
geological conditions;
•
changes in governmental regulations and taxation;
•
assumptions governing future prices;
•
the amount and timing of actual production;
•
future operating costs; and
•
capital costs of drilling new wells.
The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. In addition, if natural gas prices decline by $0.10 per thousand cubic feet, then the pre-tax present value using a 10% discount rate of our proved reserves as of December 31, 2009 would decrease from $1.5 billion to $1.4 billion. The standardized Generally Accepted Accounting Principle measure associated with this decline of $0.10 per thousand cubic feet, would be approximately $0.8 billion.
Unless we replace our natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition, results of operations and cash flows.
Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Because total estimated proved reserves include our proved undeveloped reserves at December 31, 2009, production is expected to decline even if those proved undeveloped reserves are developed and the wells produce as expected. The rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change under other circumstances. Thus, our future natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs.
Our exploration and development activities may not be commercially successful.
The exploration for and production of gas involves numerous risks. The cost of drilling, completing and operating wells for coal bed methane (CBM) or other gas is often uncertain, and a number of factors can delay or prevent drilling operations or production, including:
•
unexpected drilling conditions;
•
title problems;
•
pressure or irregularities in geologic formations;
•
equipment failures or repairs;
•
fires or other accidents;
•
adverse weather conditions;
•
reductions in natural gas prices;
•
pipeline ruptures; and
•
unavailability or high cost of drilling rigs, other field services and equipment.
Our future drilling activities may not be successful, and our drilling success rates could decline. Unsuccessful drilling activities could result in higher costs without any corresponding revenues.
Our focus on new development projects in our operating areas and other unexplored areas increases the risks inherent in our gas and oil activities.
We have little or no proved reserves in certain areas in Pennsylvania, Kentucky and Tennessee. These exploration, drilling and production activities will be subject to many risks, including the risk that CBM or other natural gas is not present in sufficient quantities in the coal seam or target strata, or that sufficient permeability does not exist for the gas to be produced economically. We have invested in property, and will continue to invest in property, including undeveloped leasehold acreage, that we believe will result in projects that will add value over time. Drilling for CBM, other natural gas and oil may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting drilling, operating and other costs. We cannot be certain that the wells we drill in these new areas will be productive or that we will recover all or any portion of our investments.
Our business depends on transportation facilities owned by others. Disruption of, capacity constraints in, or proximity to pipeline systems could limit sales of our gas.
We transport our gas to market by utilizing pipelines owned by others. If pipelines do not exist near our producing wells, if pipeline capacity is limited or if pipeline capacity is unexpectedly disrupted, our gas sales could be limited, reducing our profitability. If we cannot access pipeline transportation, we may have to reduce our production of gas or vent our produced gas to the atmosphere because we do not have facilities to store excess inventory. If our sales are reduced because of transportation constraints, our revenues will be reduced, and our unit costs will also increase. If we cannot obtain transportation capacity and we do not have the ability to store gas, we may have to reduce production. If pipeline quality tariffs change, we might be required to install additional processing equipment which could increase our costs. The pipeline could curtail our flows until the gas delivered to their pipeline is in compliance.
Increased industry activity may create shortages of field services, equipment and personnel, which may increase our costs and may limit our ability to drill and produce from our natural gas properties.
The demand for well service providers, related equipment, and qualified and experienced field personnel to drill wells and conduct field operations, including geologists, geophysicists, engineers and other professionals in the natural gas and oil industry can fluctuate significantly, often in correlation with natural gas and oil prices,
causing periodic shortages. These shortages may lead to escalating prices, the possibility of poor services, inefficient drilling operations, and personnel injuries. Such pressures will likely increase the actual cost of services, extend the time to secure such services and add costs for damages due to accidents sustained from the over use of equipment and inexperienced personnel. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling equipment, crews and associated supplies, equipment and services. In addition, the costs and delivery times of equipment and supplies are substantially greater in periods of peak demand. Accordingly, we cannot assure that we will be able to obtain necessary drilling equipment and supplies in a timely manner or on satisfactory terms, and we may experience shortages of, or material increases in the cost of, drilling equipment, crews and associated supplies, equipment and services in the future. Any such delays and price increases could adversely affect our ability to pursue our drilling program and our results of operations.
We may incur additional costs and delays to produce gas because we have to acquire additional property rights to perfect our title to the gas estate.
Some of the gas rights we believe we control are in areas where we have not yet done any exploratory or production drilling. Most of these properties were acquired primarily for the coal rights, and, in many cases were acquired years ago. While chain of title work for the coal estate was generally fully developed, in many cases, the gas estate title work is less robust. Our practice is to perform a thorough title examination of the gas estate before we commence drilling activities and to acquire any additional rights needed to perfect our ownership of the gas estate for development and production purposes. We may incur substantial costs to acquire these additional property rights and the acquisition of the necessary rights may not be feasible in some cases. Our inability to obtain these rights may adversely impact our ability to develop those properties. Some states permit us to produce the gas without perfected ownership under an administrative process known as “pooling,” which require us to give notice to all potential claimants and pay royalties into escrow until the undetermined rights are resolved. As a result, we may have to pay royalties to produce gas on acreage that we control and these costs may be material. Further, the pooling process is time-consuming and may delay our drilling program in the affected areas.
Our shale gas drilling and production operations require adequate sources of water to facilitate the fracturing process and the disposal of that water when it flows back to the well-bore, and our CBM gas drilling and production operations require the removal and disposal of water from the coal seams, from which we produce gas. If we are unable to dispose of the water we use or remove from the strata at a reasonable cost and within applicable environmental rules, our ability to produce gas commercially and in commercial quantities could be impaired.
New environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse affect on our operations and financial performance.
Coal seams, frequently contain water that must be removed in order for the gas to detach from the coal and flow to the wellbore. Further, we must remove the water that we use to fracture our shale gas wells when it flows back to the well-bore. Our ability to remove and dispose of water will affect our production and the cost of water treatment and disposal may affect our profitability. The imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct hydraulic fracturing or disposal of waste, including, produced water, drilling fluids and other wastes associated with the exploration, development and production of natural gas.
Coalbed methane and other gas that we produce often contains impurities that must be removed, and the gas must be processed before it can be sold, which can adversely affect our operations and financial performance.
A substantial amount of our gas needs to be processed in order to make it saleable to our intended customers. At times, the cost of processing this gas relative to the quantity of gas produced from a particular
well, or group of wells, may outweigh the economic benefit of selling that gas. Our profitability may decrease due to the reduced production and sale of gas.
Enactment of a severance tax in several states where we have operations, including Pennsylvania, on natural gas could adversely impact our results of existing operations and the economic viability of exploiting new gas drilling and production opportunities in those states.
As a result of a funding gap in the Pennsylvania state budget due to significant declines in anticipated tax revenues, the Pennsylvania governor has proposed to its legislature the adoption of a wellhead or severance tax on the production of natural gas in Pennsylvania. The amount of the proposed tax is 5 percent of the value of the natural gas at wellhead plus 4.7 cents per thousand cubic feet of natural gas severed. In Pennsylvania we have rights in significant acreage for coalbed methane and other natural gas extraction on which we have drilled and expect to continue to drill producing wells. In 2009, 17% or 18.4 billion cubic feet, of our production was from Pennsylvania. In addition, a significant amount of our Marcellus shale play acreage is in Pennsylvania. We cannot predict whether Pennsylvania (or any other states) will adopt any such tax, nor if adopted the rate of tax. If states adopt such taxes, it could adversely impact our results of existing operations and the economic viability of exploiting new gas drilling and production opportunities.
Currently the majority of our producing properties are located in three counties in southwestern Virginia, making us vulnerable to risks associated with having our production concentrated in one area.
The vast majority of our producing properties are geographically concentrated in three counties in Virginia. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by significant governmental regulation, transportation capacity constraints, curtailment of production, natural disasters or interruption of transportation of natural gas produced from the wells in this basin or other events which impact this area.
Our hedging activities may prevent us from benefiting from price increases and may expose us to other risks.
To manage our exposure to fluctuations in the price of natural gas, we enter into hedging arrangements with respect to a portion of our expected production. As of December 31, 2009, we had hedges on approximately 45.7 billion cubic feet of our 2010 natural gas production, 22.6 billion cubic feet of our 2011 natural gas production and 15.1 billion cubic feet of our 2012 natural gas production. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of price increases above the levels of the hedges.
In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:
•
our production is less than expected;
•
the counterparties to our contracts fail to perform the contracts; or
•
the creditworthiness of our counterparties or their guarantors is substantially impaired.
If our gas hedges would no longer qualify for hedge accounting, we will be required to mark them to market and recognize the adjustments through current year earnings. This may result in more volatility in our income in future periods.
Item 1B.
Item 1B. Unresolved Staff Comments.
None.
Item 2.
Item 2. Properties.
See “Coal Operations” and “Gas Operations” in Item 1 of this 10-K for a description of CONSOL Energy’s properties.
Item 3.
Item 3. Legal Proceedings.
The first through eighteenth paragraphs of Note 24 of the Notes to the Audited Consolidated Financial Statements included as Item 8 in Part II of this Form 10-K are incorporated herein by reference.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities.
Common Stock Market Prices and Dividends
Our common stock is listed on the New York Stock Exchange under the symbol CNX. The following table sets forth for the periods indicated the range of high and low sales prices per share of our common stock as reported on the New York Stock Exchange and the cash dividends declared on the common stock for the periods indicated:
As of December 31, 2009, there were 186 holders of record of our common stock. The computation of the approximate number of shareholders is based upon a broker search.
The following performance graph compares the yearly percentage change in the cumulative total shareholder return on the common stock of CONSOL Energy to the cumulative shareholder return for the same period of a peer group and the Standard & Poor’s 500 Stock Index. The peer group is comprised of CONSOL Energy, Alliance Resource Partners, Alpha Natural Resources, Inc., Anadarko Petroleum Corp., Apache Corp., Arch Coal, Inc., Cabot Oil & Gas Corp., Callon Petroleum Co., Cheasapeake Energy, Corp., Climarex Energy, Co., Comstock Resources, Inc., Denbury Resources, Inc., Devon Energy Corp., Encana Corp., EOG Resources, Inc., International Coal Group, Inc., James River Coal Co., Massey Energy Co., Newfield Exploration Co., Nexen Inc., Noble Energy Inc., Peabody Energy Corp., Penn Virginia Corp., Pioneer Natural Resources Co., Rio Tinto PLC (ADR), St. Mary Land & Exploration, Stone Energy Corp., Ultra Petroleum Corp., and Westmorland Coal Co. The graph assumes that the value of the investment in CONSOL Energy common stock and each index was $100 at December 31, 2004. The graph also assumes that all dividends were reinvested and that the investments were held through December 31, 2009.
Cumulative Total Shareholder Return Among CONSOL Energy Inc., Peer Group and
S&P 500 Stock Index
The above information is being furnished pursuant to Regulation S-K, Item 201 (e) (Performance Graph).
On January 29, 2010, CONSOL Energy’s board of directors declared a dividend of $0.10 per share, payable on February 19, 2010, to shareholders of record on February 9, 2010.
The declaration and payment of dividends by CONSOL Energy is subject to the discretion of CONSOL Energy’s Board of Directors, and no assurance can be given that CONSOL Energy will pay dividends in the future. CONSOL Energy’s Board of Directors determines whether dividends will be paid quarterly. The determination to pay dividends will depend upon, among other things, general business conditions, CONSOL Energy’s financial results, contractual and legal restrictions regarding the payment of dividends by CONSOL Energy, planned investments by CONSOL Energy and such other factors as the board of directors deems relevant. Our credit facility limits our ability to pay dividends when our leverage ratio covenant is 2.50 to 1.00 or greater or our availability is less than $100 million. The leverage ratio was 0.87 to 1.00 and our availability was approximately $317 million at December 31, 2009. The credit facility does not permit dividend payments in the event of defaults. There were no defaults in the year ended December 31, 2009.
See Part III, Item 12. “Security ownership of Certain Beneficial Owners and Management and Related Stockholders Matters” for information relating to CONSOL Energy’s equity compensation plans.
Item 6.
Item 6. Selected Financial Data.
The following table presents our selected consolidated financial and operating data for, and as of the end of, each of the periods indicated. The selected consolidated financial data for, and as of the end of, each of the years ended December 31, 2009, 2008, 2007, 2006 and 2005 are derived from our audited Consolidated Financial Statements. Certain reclassifications of prior year data have been made to conform to the year ended December 31, 2009 as required by the Noncontrolling Interest Topic of the Financial Accounting Standards Board Accounting Standards Codification. The selected consolidated financial and operating data are not necessarily indicative of the results that may be expected for any future period. The selected consolidated financial and operating data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and related notes included in this report.
STATEMENT OF INCOME DATA
(In thousands except per share data)
BALANCE SHEET DATA
(In thousands)
OTHER OPERATING DATA
(unaudited)
CASH FLOW STATEMENT DATA
(In thousands)
OTHER FINANCIAL DATA
(Unaudited)
(In thousands)
(A) See Note 25 of Notes to the Audited Consolidated Financial Statements for sales and freight by operating segment.
(B) Basic earnings per share are computed using weighted average shares outstanding. Differences in the weighted average number of shares outstanding for purposes of computing dilutive earnings per share are due to the inclusion of the weighted average dilutive effect of employee and non-employee share-based compensation granted, totaling 2,127,893 shares, 2,293,581 shares, 2,099,124 shares, 2,283,374 shares, and 2,045,072 shares for the year ended December 31, 2009, 2008, 2007, 2006 and 2005, respectively.
(C) On May 4, 2006, CONSOL Energy’s Board of Directors declared a two-for-one stock split of the common stock. The stock split resulted in the issuance of approximately 92.5 million additional shares of common stock. Shares and earnings per share for all periods presented are reflected on a post-split basis.
(D) Includes sales of coal produced by CONSOL Energy and purchased from third parties. Of the tons sold, CONSOL Energy purchased the following amount from third parties: 0.3 million tons in the year ended December 31, 2009, 1.7 million tons in the year ended December 31, 2008, 0.5 million tons in the year ended December 31, 2007, 1.3 million tons in the year ended December 31, 2006 and 1.5 million tons in year ended December 31, 2005.
(E) Amounts include intersegment transactions. For entities that are not wholly owned but in which CONSOL Energy owns an equity interest, includes a percentage of their net production, sales and reserves equal to CONSOL Energy’s percentage equity ownership. For coal, the proportionate share of recoverable reserves for equity affiliates was 170, 171 and 179 tons at December 31, 2009, 2008 and 2007 respectively. Sales of coal produced by equity affiliates were 0.4 million tons in the year ended December 31, 2009, 0.2 million tons in the year ended December 31, 2008 and 0.1 million ton in the year ended December 31, 2007. Recoverable reserves and production amounts related to 2006 and 2005 for coal equity affiliates were immaterial. For gas, amounts include 100% of CNX Gas’ basis; they exclude the noncontrolling interest reduction. There was no equity in affiliates at December 31, 2009 and 2008. The proportionate share of proved gas reserves for equity affiliates was 3.6 Bcfe at December 31, 2007, 2.2 Bcfe at December 31, 2006 and 2.7 Bcfe at December 31, 2005. Sales of gas produced by equity affiliates were 0.32 Bcfe for the year ended December 31, 2007, 0.22 Bcfe for the year ended December 2006, 0.23 Bcfe for the year ended December 31, 2005.
(F) Represents proven and probable coal reserves at period end.
(G) Represents average net sales price including the effect of derivative transactions.
(H) Represents proved developed and undeveloped gas reserves at period end.
(I) EBIT is defined as earnings before deducting net interest expense (interest expense less interest income) and income taxes. EBITDA is defined as earnings before deducting net interest expense (interest expense less interest income), income taxes and depreciation, depletion and amortization. Although EBIT and EBITDA are not measures of performance calculated in accordance with generally accepted accounting principles, management believes that they are useful to an investor in evaluating CONSOL Energy because they are widely used in the coal industry as measures to evaluate a company’s operating performance before debt expense and cash flow. Financial covenants in our credit facility include ratios based on EBITDA. EBIT and EBITDA do not purport to represent cash generated by operating activities and should not be considered in isolation or as a substitute for measures of performance in accordance with generally accepted accounting principles. In addition, because EBIT and EBITDA are not calculated identically by all companies, the presentation here may not be comparable to other similarly titled measures of other companies. Management’s discretionary use of funds depicted by EBIT and EBITDA may be limited by working capital, debt service and capital expenditure requirements, and by restrictions related to legal requirements, commitments and uncertainties. A reconcilement of EBIT and EBITDA to financial net income is as follows:
(Unaudited)
(In thousands)
(J) For purposes of computing the ratio of earnings to fixed charges, earnings represent income before income taxes plus fixed charges. Fixed charges include (a) interest on indebtedness (whether expensed or capitalized), (b) amortization of debt discounts and premiums and capitalized expenses related to indebtedness and (c) the portion of rent expense we believe to be representative of interest.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
General
The U.S. economy began growing in the third quarter of 2009 and continued growing in the fourth quarter. Due to the significant fiscal spending and relaxed monetary policy in the United States, a modest recovery appears likely to continue in the U.S. through 2010. This should lead to an increase in demand for energy products from industrial customers, power generators and steel producers. Depending on the pace and sustainability of the recovery, we believe substantial opportunities exist for our metallurgical coal, thermal coal, and gas businesses.
Steel plant capacity utilization rates in the U.S. and globally continue to improve compared to last year. Domestic steel mills are using approximately 65% of their capacity, while Asian steel mills currently are using about 82% of their capacity. Chinese steel demand is again driving world demand and pricing for coking coal. Through its arrangement with Xcoal, CONSOL expects to increase its sales to Asian mills throughout 2010.
Going into the fourth quarter, thermal coal inventories were at historic highs. Because of the colder than normal weather in December 2009 and early January 2010, inventories at coal-fired power generators have been significantly drawn down, but are still somewhat higher than normal. Customers in our major market area (the PJM power pool) had an estimated 55-60 days of inventory on hand as of mid-January. The Company believes that thermal coal inventories could return to normal by mid-year. The outlook for a gradual economic recovery with strengthening demand and higher gas prices combined with the production declines over the past year are expected to tighten the thermal coal markets and support higher pricing. Higher gas prices in 2010 should result in power generators switching back from gas to coal based on dispatch economics. We anticipate up to 30 million tons of coal generation could displace natural gas generation in 2010. In addition, approximately 19 gigawatts of new coal-fired electricity generation capacity is set to come online by the end of 2012. This new demand, coupled with permanent cuts in coal production as well as safety and regulatory issues, is setting the stage for coal supply shortages over the next few years. With the continued build-out of scrubbers by generators, increased economic activity and its low cost position, CONSOL Energy is in a position to increase market share.
At the onset of the winter heating season, natural gas in storage fields was at record high levels. Because of much colder than normal weather in much of the U.S. from mid-December through mid-January, gas in storage has been drawn down to normal levels. The economic recovery is expected to positively affect industrial and commercial demand.
CONSOL Energy established an arrangement with Xcoal to market CONSOL Energy coal in Asia. In January 2010, we sold a vessel of high-vol coking coal from Bailey Mine in Northern Appalachia to merchant coke plants in China. This re-branding of Bailey Mine coal from a premium thermal coal to a high-volatile coking coal has meaningful implications for CONSOL Energy’s 2010 earnings and beyond. Our goal in 2010 is to sell 500,000 tons of Northern Appalachia high-volatile coking coal into Asian markets.
In 2009, a fish kill occurred in Dunkard Creek, which is a creek with segments in both Pennsylvania and West Virginia. The fish kill was caused by the growth of golden brown algae in the creek, which appears to be an invasive species, not indigenous to the area. A CONSOL Energy subsidiary discharges water into Dunkard Creek, after treatment, from its Blacksville No. 2 Mine and from its Loveridge Mine. This water has levels of chlorides that are higher than West Virginia in-stream limits. The subsidiary is subject to a state administrative order in West Virginia that requires compliance in 2013 with effluent limits for chlorides for discharges from four active and two closed underground coal mines in northern West Virginia. Given the volumes of water involved and the options that are available to timely meet the effluent limits, it is likely that it will be necessary to construct one or more treatment facilities using advanced water treatment technologies. These requirements may cause CONSOL Energy to incur additional costs that could adversely affect our operating results, financial condition and cash flows.
Results of Operations
Year Ended December 31, 2009 Compared with Year Ended December 31, 2008
Net Income Attributable to CONSOL Energy Shareholders
Net income attributable to CONSOL Energy shareholders changed primarily due to the following items
(table in millions):
Net income attributable to CONSOL Energy shareholders for the year ended December 31, 2009 was $540 million compared to $442 million in the year ended December 31, 2008. Net income attributable to CONSOL Energy shareholders for the year ended December 31, 2009 increased in comparison to the year ended December 31, 2008 primarily due to:
•
Higher average thermal coal sales prices;
•
Higher gas sales volumes; and
•
Lower average cost per unit of gas sold.
Improvements in net income attributable to CONSOL Energy shareholders were offset, in part, by the following items:
•
Lower volume of thermal and metallurgical coal sold;
•
Lower average sales prices for gas volumes sold;
•
Lower average sales prices for metallurgical tons sold;
•
Higher average cost per ton of coal sold;
•
Business interruption insurance settlement of $50 million recognized in the year ended December 31, 2008 related to the Buchanan roof collapse incident; and
•
Black lung excise tax refunds of $56 million recognized in the year ended December 31, 2008.
See discussion below for additional details of the changes in net income in the year-to-year comparison. The cost per unit below is not necessarily indicative of unit costs in the future.
Revenue
Revenue and other income decreased due to the following items:
The increase in company produced thermal coal sales revenue during the year ended December 31, 2009 was due to the higher average price per ton sold, offset, in part, by lower sales volumes of company produced thermal coal sold.
The increase in average sales price in the year-to-year comparison primarily reflects higher prices negotiated in previous periods when there was a significant increase in the global demand for coal. Sales of company produced coal shipments decreased in the current period due to delivery deferments of Central and Northern Appalachian coals. Coal consumption by the electric power sector continued to decline during the year. In the year-to-year comparison of the thermal coal changes, the increased pricing improved sales income by $753 million. This was partially offset by lower thermal tons sold which reduced sales income by approximately $274 million dollars.
The decrease in company produced metallurgical coal sales revenue during the year ended December 31, 2009 was due to the lower average price per ton sold and lower sales volumes of company produced metallurgical coal sold.
The decrease in average sales price for metallurgical coal in the year-to-year comparison reflects lower prices realized due to a downturn in the domestic and international steel business and the deferment of previously negotiated pricing into future periods. Sales of company produced metallurgical coal decreased in the current period due to a downturn in the domestic and international steel business resulting in reduced demand for metallurgical coal and the idling of the Buchanan Mine from March 1, 2009 to August 7, 2009. In the year-to-year comparison of metallurgical coal changes, the decreased pricing impaired sales income by $93 million. Also, lower metallurgical tons sold impaired sales income by approximately $82 million dollars.
Purchased coal sales consist of revenues from processing third-party coal in our preparation plants for blending purposes to meet customer coal specifications, coal purchased from third parties and sold directly to our customers and revenues from processing third-party coal in our preparation plants. The decrease of $79 million in purchased coal sales revenue was primarily due to a decrease in demand in the year-to-year comparison, offset, in part, by higher sales prices.
The decrease of $52 million in produced gas sales revenue in the year ended December 31, 2009 compared to the year ended December 31, 2008 was due to lower average sales price per thousand cubic feet sold, offset, in part, by higher sales volumes.
Sales volumes increased as a result of additional wells coming online from our on-going drilling program. The decrease in average sales price is the result of the general market price decreases in the year-to-year comparison. The general market price decline was offset, in part, by the various gas swap transactions entered into by CNX Gas. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 51.6 billion cubic feet of our produced gas sales volumes for the year ended December 31, 2009 at an average price of $8.76 per thousand cubic feet. In the year ended December 31, 2008, these financial hedges represented approximately 43.4 billion cubic feet at an average price of $9.25 per thousand cubic feet.
The $1 million decrease in revenues from the sale of industrial supplies was primarily due to lower sales volumes. Economic conditions had a negative impact on major customers, particularly those serving the auto and housing markets.
The $42 million decrease in other sales was attributable to decreased revenues from barge towing and terminal services. The decrease is related to lower tonnage moved by the barge towing and terminal services in the year ended December 31, 2009 compared to the year ended December 31, 2008. Lower tonnage moved reflects the weak economic environment which has reduced the volume of products moved on the rivers in the year ended December 31, 2009.
Royalty interest gas sales represent the revenues related to the portion of production belonging to royalty interest owners sold by CNX Gas on their behalf. The decrease in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the year-to-year change.
Purchased gas sales volumes represent volumes of gas, sold at market prices, that were purchased from third-party producers.
Freight revenue is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e., rail, barge, truck, etc.) used for the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight revenue has decreased $69 million in 2009 primarily due to lower domestic shipments to customers for whom CONSOL Energy pays the freight and then passes on the cost to the customer. Freight revenue also decreased due to fewer export sales made to customers whom CONSOL Energy pays the ocean-going freight and then passes the cost to the customer.
Other income consists of interest income, gain or loss on the disposition of assets, equity in earnings of affiliates, service income, royalty income and miscellaneous income.
In March 2008, CONSOL Energy received notice from its insurance carriers that $50 million would be paid as final settlement of the insurance claim related to the July 2007 Buchanan Mine incident that idled the mine. The $50 million represented business interruption coverage which was recognized in other income; the coal segment recognized $42 million and the gas segment recognized $8 million. The final settlement brought the total amount recovered from insurance carriers to $75 million, the maximum allowed per covered event.
Gain on sale of assets decreased $8 million in the year-to-year comparison due to 2008 including the sale of an idled facility which included the transfer of the mine closing liabilities to the buyer. This transaction resulted in $8 million pre-tax gain in 2008. Both periods also include various miscellaneous transactions, none of which were individually material.
Contract towing revenue has decreased approximately $6 million due primarily to the general slow-down in the economy negatively impacting the volume of material being shipped via river transportation.
The year ended December 31, 2008 includes $6 million of proceeds received from a third party in order for CONSOL Energy to relinquish the mining of certain in-place coal reserves.
Royalty income decreased $4 million primarily due to lower volumes of CONSOL Energy coal produced by third-parties.
In 2009, mark-to-market adjustments for free standing coal sales options resulted in approximately a $2 million reversal of previously recognized unrealized losses. The reversal of losses was due to the options expiring during the year ended December 31, 2009.
Interest income increased $3 million primarily due to higher average cash balances available to invest in the year-to-year comparison.
Equity in earnings of affiliates increased $5 million in the year ended December 31, 2009 due to various transactions entered into by our equity affiliates throughout both periods, none of which were individually material.
In 2009, $12 million of income was recognized related to contracts with certain customers that were unable to take delivery of previously contracted coal tonnage. These customers agreed to buy out their contracts in order to release them from the requirement of taking delivery of previously committed tons.
Other miscellaneous income decreased $1 million in the year-to-year comparison due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.
Costs
Cost of goods sold and other charges decreased due to the following:
Produced coal cost of goods sold and other charges decreased primarily due to lower sales volumes, offset, in part, by an 8.6% increase in average unit cost per ton sold.
Average cost of goods sold and other charges per unit increased in the year-to-year comparison primarily due to an increase in average unit costs related to the following items:
•
In general, average cost of goods sold per unit has increased due to the reduced amount of tons sold from CONSOL Energy mines. The reduction in tons sold reflects the weak economic environment which has affected electricity generation and correspondingly the demand for coal. Fixed costs incurred at our mining operations are now spread over fewer tons sold, which has negatively impacted average unit costs.
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Supply costs have increased $1.39 per ton sold related to higher supply and maintenance costs at several locations. Additional supply and maintenance projects were related to additional preparation
plant maintenance, additional belt advancement costs, additional mining equipment maintenance, additional roof support, additional use of contract labor to complete belt projects and additional water handling costs. These increased supply and maintenance costs were offset, in part, by fewer seals being constructed in previously mined areas. Average unit costs of supplies were also impacted by lower sales tons in the year-to-year comparison.
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Labor costs have increased $0.91 per ton sold due to the effects of wage increases at the union and non-union mines. These contracts call for specified hourly wage increases in each year of the contract. The average increase in unit cost for labor was also impacted by lower sales volumes due to the economic environment as discussed above.
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United Mine Workers of America (UMWA) health and retirement plan expenses have increased $0.30 per ton sold primarily due to the effects of the 2007 labor contract that require additional contributions to be made into employee benefit funds. The contribution increase over 2007 was $0.42 per United Mine Worker of America hour worked. The average increase in unit costs for health and retirement plans was also impacted by lower sales tons in the year-to-year comparison.
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Subsidence cost increased $0.30 per ton sold primarily due to the year ended December 31, 2009 including additional expenses related to work to be performed on streams that have been impacted by underground mining in Pennsylvania. The average increase in unit costs for subsidence was also impacted by lower sales tons in the year-to-year comparison.
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Other costs per unit on a net basis have increased $0.05 per ton sold due to various transactions that have occurred throughout both periods, none of which were individually material.
These increases in costs were offset, in part, by the following decrease:
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Contract Mining Fees decreased $0.25 per ton sold due to lower contractor usage in the year ended December 31, 2009 compared to the year ended December 31, 2008.
Purchased coal cost of goods sold consists of costs from processing purchased coal in our preparation plants for blending purposes to meet customer coal specifications, coal purchased and sold directly to the customer and costs for processing third party coal in our preparation plants. The decrease of $78 million in purchased coal cost of goods sold and other charges in 2009 was primarily due to lower volumes purchased.
Gas cost of goods sold and other charges increased primarily due to a 24.3% increase in volumes of produced gas sold, offset, in part, by lower average cost per unit sold.
Average costs per unit decreased in the year ended December 31, 2009 as a result of several factors:
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Well service costs have decreased by $0.07 per thousand cubic feet due to lower contract service rig hours needed as a result of less pump maintenance being required in 2009.
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Gob collection charges were $0.04 per thousand cubic feet lower in the year-to-year comparison. Lower gob collection charges per unit were primarily due to the Buchanan longwall being idled throughout some of 2009.
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Compression expenses decreased $0.03 per thousand cubic feet primarily due to a reduction in the number of compressors utilized in the Northern Appalachian production field. Due to the slow-down in the drilling program in Northern Appalachia, rented compressors have been returned to more appropriately design the gathering fields for existing needs.
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Other costs have decreased $0.22 per thousand cubic feet primarily due to the impact of additional volumes of gas sold during the year ended December 31, 2009. Dollars spent remained consistent in the year-to-year comparisons, therefore additional volumes decreased the unit costs.
These decreases in unit costs were offset, in part, by the following:
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Idle drilling costs were $0.09 per thousand cubic feet related to idling various drilling rigs throughout the company. Some of CNX Gas’ drilling contracts require minimum payments be made to the contracting party when drilling rigs are not being used. The CNX Gas drilling program has been slowed down pending a change in the economic environment. These charges resulted in an increase to costs.
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Firm transportation costs increased $0.08 per thousand cubic feet primarily due to acquiring additional capacity in the Northern Appalachian region after December 31, 2008.
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Power and fuel costs increased $0.04 per thousand cubic feet due to a power rate increase which occurred after December 31, 2008. Also, the increase was due to additional compressors being placed in service after December 31, 2008 along the existing gathering system in the Central Appalachian production field in order to flow the increasing gas volumes more efficiently.
Industrial supplies cost of goods sold decreased $1 million primarily due to decreased sales volumes.
Closed and idle mine cost of goods sold increased approximately $36 million in 2009 compared to 2008. Approximately $38 million of increased expenses were incurred at Mine 84 to pull underground equipment out of the mine in preparation of idling and to construct seals to close sections of the underground mine works so that the mine can be maintained in a more efficient manner. Increases were also attributable to the idled Shoemaker Mine incurring approximately $11 million of additional expenses in the current period related to the continued maintenance of the mine in an idled status. Closed and idle mine cost of goods sold also increased $7 million primarily due to the periodic idling of various other locations throughout 2009 due to the economic environment. These increases were offset, in part, by reductions of $20 million related to mine closing, reclamation and water treatment liabilities. These decreases primarily related to adjustments in engineering estimates of water quality and flows, as well as changes in the credit adjusted risk free interest rates.
Other cost of goods sold remained consistent due to the following items:
The incentive compensation program is designed to increase compensation to eligible employees when CONSOL Energy reaches predetermined production, safety and cost targets and the employees reach predetermined performance targets. Incentive compensation expense increased $18 million in 2009 due to exceeding the predetermined targets.
Legal settlement of $15 million represents the amount expensed for the settlement of the Levisa Action and the Pobst/Combs Action.
Approximately $14 million of cease use expense relates to the relocation of the CONSOL Energy and CNX Gas corporate office and the cease use of the old facilities. Accordingly, a liability for the present value of the remaining lease payments for the previous corporate offices has been recognized in Cost of Goods Sold and Other Charges and resulted in $14 million of expense.
Dry hole and other costs of $9 million were incurred by the gas segment in the year ended December 31, 2009. Dry hole and other costs were incurred in 2009 related to the determination that certain areas where an exploration well was drilled would not be economical to pursue. The costs for the exploration well, which were previously capitalized, were expensed. Other costs include costs associated with certain leased property that will no longer be held due to the determination that the area would not be economical to pursue. Also, costs related to particular permits for areas where management has determined that no drilling will take place have been expensed.
Stock-based compensation expense increased $4 million in the year-to-year comparison primarily due to $3 million of fair value adjustments associated with the exchange offer to convert CNX Gas performance share units into CONSOL restricted stock units. The year ended December 31, 2009 also includes additional expense due to expanding the stock-based compensation program to include additional employees. The year ended December 31, 2008 included a reduction to expense related to the CNX Gas performance share units to reflect the lower market price of CNX Gas shares at December 31, 2008 compared to its peer group. The CNX Gas performance share units were replaced with a CONSOL Energy restricted stock units in 2009.
Severance pay relates to the administrative staff reductions in force and resulted in $4 million of expense in 2009.
Ward transformer superfund site expense was $4 million lower in the year ended December 31, 2009 compared to the year ended December 31, 2008. The expense in each period represents CONSOL Energy’s portion of the latest estimate of cost to remediate the site. See “Note 24-Commitments and Contingencies” of Item 8 of the Consolidated Financial Statements for additional detail.
The year ended December 31, 2008 includes adjustments related to CONSOL Energy agreements to buy out coal sales contracts with several customers in order to release tons committed under lower priced contracts for sale to other customers at higher prices. The year ended December 31, 2009 includes fewer customer buyouts.
In the year ended December 31, 2008, cost of goods sold and other charges includes $15 million related to contracts with certain customers who were unable to take delivery of previously contracted coal tonnage. These customers agreed to allow CONSOL Energy to sell the released tonnage, but required CONSOL Energy to split the incremental sales price over the original contract sales price evenly with them. The $15 million represents the additional sales price received for the tonnage sold that is owed to the original customer.
In July 2007, production at the Buchanan Mine was suspended after several roof falls in previously mined areas damaged some of the ventilation controls inside the mine, requiring a general evacuation of the mine. In 2008, $17 million of cost of goods sold and other charges related to the Buchanan Mine event were incurred.
Terminal/River operation charges have decreased approximately $22 million in the year-to-year comparison due to lower tonnage moved and lower employee counts throughout the year ended December 31, 2009.
Miscellaneous other cost of goods sold and other charges increased $1 million due to various transactions throughout both years, none of which were individually material.
Royalty interest gas sales represent the revenues related to the portion of production belonging to royalty interest owners sold by CNX Gas on their behalf. The decrease in market prices, contractual differences among leases, and the mix of average and index prices used in calculating royalties contributed to the year-to-year change.
Purchased gas costs represent volumes of gas purchased from third party producers that we sell at market prices. Purchased gas cost volumes also reflect the impact of pipeline imbalances. The decrease in cost of goods sold and other charges related to purchased gas represents overall price changes and contractual differences among customers in the year-to-year comparison.
Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e., rail, barge, truck, etc.) used for the customers to which CONSOL Energy contractually provides transportation services. Freight expense is the amount billed to customers for transportation costs incurred. Freight expense has decreased $69 million in the year ended December 31, 2009 primarily due to lower domestic shipments to customers whom CONSOL Energy pays the freight and then passes on the cost to the customer. Freight revenue also decreased due to fewer export sales made to customers whom CONSOL Energy pays the ocean-going freight and then passes the cost to the customer.
Selling, general and administrative costs have increased due to the following items:
Rentals have increased $6 million primarily due to rent expense related to the new CONSOL Energy headquarters, offset, in part, by reduced rent related to the previous CONSOL Energy and CNX Gas corporate office space that is no longer used.
Wages, salaries and related benefits have increased approximately $2 million primarily due to annual salary increases and additional recruiting expenses.
Association assessments and charitable contributions have remained consistent in the year-to-year comparison.
Advertising and promotion expenses have decreased $1 million in the year-to-year comparison due to the timing of various campaigns.
Costs of professional, consulting and other purchased services have decreased $1 million related to various corporate initiatives, none of which are individually material.
Other selling, general and administrative costs increased $1 million related to various transactions none of which are individually material.
Depreciation, depletion and amortization increased due to the following items:
The $8 million increase in coal depreciation, depletion and amortization was primarily attributable to assets placed in service during 2009.
The increase in gas production depreciation, depletion and amortization was primarily due to increased volumes produced, combined with an increase in the units of production rates for the Northern Appalachian region in the year-to-year comparison. These rates increased due to the higher proportion of capital assets placed in service versus the proportion of proved developed reserve additions. These rates are generally calculated using the net book value of assets at the end of the previous year divided by either proved or proved developed reserves. Production asset depreciation also increased due to the recalculation of rates in 2009 related to the Marcellus Shale wells and various other assets being placed in service during 2009.
Gas gathering depreciation, depletion and amortization is recorded using the straight-line method and increased $2 million in the year-to-year comparison due to various assets being placed in service during 2009.
Other depreciation increased $2 million in the year-to-year comparison due to various assets being placed in service during 2009, none of which were individually material.
Interest expense decreased in the year ended December 31, 2009 compared to the year ended December 31, 2008 due to the following items:
Revolver interest expense is related to the amounts drawn on the credit facility. The decrease is related to lower interest rates on the facility in 2009 compared to 2008, offset, in part, by higher average amounts drawn in 2009.
Interest on unrecognized tax benefits, capitalize leases and long-term secured notes remained consistent in the year-to-year comparison.
Other interest expense increased $1 million in the year-to-year comparison due to various transactions that occurred throughout both periods, none of which were individually material.
Taxes other than income remained consistent in the year-to-year comparison.
Increased coal production taxes are primarily due to higher severance taxes attributable to the increase in average sales price for produced coal. These improvements were offset, in part, by lower coal production volumes in the year-to-year comparison.
Gas production taxes decreased $14 million due to lower severance taxes attributable to lower average sales prices for gas, offset, in part, by higher gas sales volumes. Lower severance taxes in the year-to-year comparison are also related to a revised estimate of a pending litigation settlement.
Other coal taxes have increased approximately $3 million primarily due to higher property taxes related to reassessments on property primarily in West Virginia and Pennsylvania owned by CONSOL Energy. The increase was also due to a reduction in the tax credit generated by production in the state of Virginia as a result of the idling of the longwall at the Buchanan Mine which reduced production during a portion of 2009.
Other gas taxes increased $1 million due to various transactions that occurred throughout both periods, none of which were individually material.
Other taxes have increased $2 million in the year-to-year comparison due to various transactions that occurred throughout both periods, none of which were individually material.
In 2008, $56 million of refunds related to black lung excise taxes were recognized. The refunds related to the Emergency Economic Stabilization Act of 2008 (the EESA Act) which was signed into law on October 3, 2008. The EESA Act contained a section that authorized certain coal producers and exporters who had filed a black lung excise tax (BLET) return on or after October 1, 1990, to request a refund of the BLET paid on export sales. The EESA Act required the U.S. Treasury to refund an amount equal to the BLET erroneously paid on export sales in prior years along with interest computed at the statutory rates applicable to overpayments. CONSOL Energy recognized, and subsequently received, approximately $56 million of BLET refunds. Approximately $1 million of additional interest income was recognized in 2009 to adjust estimated interest on these claims to the amount of interest received.
Income Taxes
CONSOL Energy’s effective income tax rate is sensitive to changes to the relationship between pre-tax earnings and percentage depletion. The proportion of coal pre-tax earnings and gas pre-tax earnings also impacts the benefit of percentage depletion on the effective tax rate. See “Note 6-Income Taxes” in Item 8, Consolidated Financial Statements of this Form 10-K.
Noncontrolling Interest
Noncontrolling interest represents 16.7% of CNX Gas net income which CONSOL Energy does not own.
Results of Operations
Year Ended December 31, 2008 Compared with Year Ended December 31, 2007
Net Income
Net income changed primarily due to the following items (table in millions):
CONSOL Energy had net income of $442 million for the year ended December 31, 2008 compared to $268 million in the year ended December 31, 2007. Net income for 2008 increased in comparison to 2007 due to:
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higher average prices received for both coal and gas;
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higher volumes of gas sold;
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2007 included a total of approximately $94 million of pre-tax expenses, net of insurance recoveries, related to the Buchanan Mine incident that occurred in July 2007 which idled the mine through March 2008; the 2008 period includes approximately $28.6 million of pre-tax income related to this incident;
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Black Lung excise tax refund receivable recognized for taxes paid in 1991-1993 due to legislation passed in October 2008; and
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Receivable write off of $24 million in 2007 related to the Supreme Court decision which rendered the Black Lung Excise Tax receivable for 1991-1993 uncollectible.
These increases in net income were offset, in part, by:
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an asset exchange and an asset sale in 2007 that resulted in pretax income of approximately $100 million and net income of approximately $59 million;
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increased unit cost of goods sold and other charges for both coal and gas.
See below for a more detailed description of variances noted. The cost per unit below is not necessarily indicative of unit costs in the future.
Revenue
Revenue and other income increased due to the following items:
The increase in company produced coal sales revenue during 2008 was due to higher average prices, offset, in part, by slightly lower volumes of produced coal sold.
The increase year-to-year in the average sales prices of coal was the result of global coal fundamentals being more favorable in 2008. Concerns regarding the adequacy of global supplies of coal had strengthened both the international and domestic coal prices and had increased the opportunity for U.S. producers to increase exports of coal. Sales tons were slightly lower in the year-to-year comparison.
Purchased coal sales consist of revenues from processing third-party coal in our preparation plants for blending purposes to meet customer coal specifications, coal purchased from third-parties and sold directly to our customers and revenues from processing third-party coal in our preparation plants. The increase of $80 million in company-purchased coal sales revenue was primarily due to an increase in volumes of purchased coal sold in the year-to-year comparison.
The increase in produced gas sales revenue in 2008 compared to 2007 was primarily due to higher average sales prices and higher volumes of gas sold.
The increase in average sales price is the result of CNX Gas, an 83.3% subsidiary at December 31, 2008, realizing general market price increases in the year-to-year comparison. CNX Gas periodically enters into various gas swap transactions that qualify as financial cash flow hedges. These gas swap transactions exist parallel to the underlying physical transactions. These financial hedges represented approximately 43.4 billion cubic feet of our produced gas sales volumes for the year ended December 31, 2008 at an average price of $9.25 per thousand cubic feet. In the prior year, these financial hedges represented approximately 18.4 billion cubic feet at an average price of $8.01 per thousand cubic feet. Sales volumes increased as a result of additional wells coming online from our on-going drilling program. Also, prior year sales volumes were impacted by the deferral of production at the Buchanan Mine.
The $49 million increase in revenues from the sale of industrial supplies was primarily due to the July 2007 acquisition of Piping & Equipment, Inc. in addition to an overall increase in sales volumes and higher sales prices.
The $31 million increase in other sales was attributable to increased revenues from barge towing and terminal services. The increase was primarily related to revenue generated from the barge towing operations having higher average rates for services rendered compared to the prior year. The barge towing operations have also increased thru-put tons and delivered tons in 2008. Increases in other sales revenues were also attributable to higher terminal services as a result of additional thru-put tons in 2008. The higher terminal revenues were offset, in part, due to services being suspended for approximately one month due to maintenance needed on a pier in Baltimore.
Gas royalty interest sales volumes represent the revenues related to the portion of production belonging to royalty interest owners sold by CNX Gas on their behalf. The increase in market prices, contractual differences among leases and the mix of average and index prices used in calculating royalties contributed to the year-to-year change.
Purchased gas sales volumes represent volumes of gas that were sold at market prices that were purchased from third-party producers, less gathering fees.
Freight revenue is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e., rail, barge, truck, etc.) used for the customers to which CONSOL Energy contractually provides transportation services. Freight revenue is the amount billed to customers for transportation costs incurred. Freight revenue has increased $30 million in 2008 due primarily to freight associated with AMVEST, which was acquired on July 31, 2007. Freight revenue has also increased due to higher freight rates being charged for
exported tons. These increases in freight revenue were offset, in part, by lower export tons shipped in 2008 compared to 2007. There were 7.0 million tons and 7.6 million tons of coal exported by CONSOL Energy in 2008 and 2007, respectively.
Other income consists of interest income, gain or loss on the disposition of assets, equity in earnings of affiliates, service income, royalty income, derivative gains and losses, rental income and miscellaneous income.
Gain on sale of assets decreased $89 million in the year-to-year comparison primarily due to two transactions that occurred in 2007. In June 2007, CONSOL Energy, through our 83.3% owned subsidiary, CNX Gas, exchanged certain coal assets in Northern Appalachia to Peabody Energy for coalbed methane and gas rights, which resulted in a pretax gain of $50 million. Also, in June 2007, CONSOL Energy, through a subsidiary, sold the rights to certain western Kentucky coal in the Illinois Basin to Alliance Resource Partners, L.P. for $53 million. This transaction also resulted in a pretax gain of approximately $50 million. The 2008 period reflects a sale of an idled facility which included the transfer of the mine closing liabilities to the buyer. This transaction resulted in a pretax gain of approximately $8 million. There was also a $3 million increase in the year-to-year comparison due to various transactions that occurred throughout both periods, none of which were individually material.
Interest income decreased $11 million in the year-to-year comparison due to lower cash balances throughout 2008 compared to 2007. Lower cash balances were primarily the result of the purchase price paid for the June 2008 acquisition of the remaining interest in Knox Energy, LLC, the July acquisition of several leases and gas wells from KIS Oil & Gas, Inc., the July 31, 2007 acquisition of AMVEST, the June 2007 purchase of certain coalbed methane and gas rights from Peabody Energy and the July 2007 Buchanan Mine incident.
A litigation settlement with a coal customer in 2007 resulted in $5 million of income. A litigation settlement with a royalty holder resulted in $1 million of income in 2008.
Equity in earnings of affiliates increased $4 million related to our interest in a specialty contracting company, our interest in a real estate development company and our interest in a coal mining company. These increases were offset, in part, by the June 2008 acquisition of our remaining interest in Knox Energy, LLC.
Income related to a railroad spur acquired with the July 2007 acquisition of AMVEST increased $3 million. This income was due to reimbursements from the rail carrier for maintenance completed on the spur during the year. The income is offset in its entirety with the related expenses reflected in cost of goods sold and other charges.
In 2008, approximately $6 million was received from a third party in order for CONSOL Energy to relinquish the mining of certain in-place coal reserves.
Royalty income increased $7 million in the year-to-year comparison due to production of CONSOL Energy coal by a third-party commencing in August 2007. Royalties have also increased due to the higher sales price of coal sold throughout 2008 compared to 2007.
The $8 million increase in contract towing services represents river towing services for third-parties which CONSOL Energy now provides. These services were minimal in 2007.
In 2008, CONSOL Energy received $50 million as final settlement of the insurance claim related to the July 2007 Buchanan Mine incident, which idled the mine from July 2007 to mid-March 2008. The $50 million represents business interruption coverage which was recognized in other income; the coal segment recognized $42 million and the gas segment recognized $8 million. CONSOL Energy had received $10 million of business interruption proceeds related to this incident in 2007; the coal segment recognized $8 million and the gas segment recognized $2 million. In 2007, $15 million was also received from the insurance carrier for reimbursement of fire brigade costs. This was recognized as a reduction of cost of goods sold and other charges as discussed below. The final settlement brought the total amount recovered from insurance carriers to $75 million, the maximum allowed per covered event. All proceeds from this insurance claim have been received.
Other miscellaneous income increased $6 million in the year-to-year comparison due to various miscellaneous transactions that occurred throughout both years, none of which were individually material.
Costs
Cost of goods sold and other charges increased due to the following:
Increased cost of goods sold and other charges for company-produced coal was due mainly to a higher average unit cost per ton sold, offset slightly by lower sales volumes.
Average cost of goods sold and other charges increased in the year-to-year comparison primarily due to an increase in average unit costs related to the following items.
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Supply and maintenance costs have increased $2.77 per ton sold due to the following items:
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The increase in supply and maintenance costs reflects the change in the mix of sales tons in 2008 compared to 2007. Production tons from the Northern Appalachian underground mines decreased, while production from the Central Appalachian mines increased. This was primarily due to the July 31, 2007 acquisition of AMVEST and to the Buchanan Mine being idled for half of 2007.
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The installation of higher grade seals and a higher number of seals being built in 2008 contributed to the increase in supply cost. The Mine Health and Safety Administration now requires higher strength seals to be constructed in order to isolate old, abandoned areas or previously sealed areas of the mine. At several locations, the installed seals are also required to be stronger. The increase in strength of seals was required to better protect the active sections of the underground mines from explosions, fires, or other situations that may occur within the sealed areas. The installation of higher strength seals and a higher number of seals being completed contributed to the increase in supply costs.
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Higher roof control costs are attributable to higher usage of products used in the mining process due to mining conditions and additional development work. Development work by continuous mining machines requires more roof support products than are used in the area of the mine where extraction is done using a longwall mining system. Roof control costs have also increased due to higher usage of “pumpable cribs” which are more expensive per unit than the standard wooden crib support. The “pumpable crib” is a canvas cylinder hung from the roof and extending to the floor into which concrete is pumped. Because the “pumpable crib” allows concrete to be pumped to the roof level, it eliminates the need to use wood shims to tighten the concrete to the roof. The “pumpable crib” is quicker to install, enhances safety due to the customized fit and minimizes the use of combustible products at underground locations. Also, roof control costs have increased due to approximately a 9% inflation rate related to roof control products.
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Gas well plugging/drilling costs related to the mining process have increased in 2008 compared to 2007. Gas well plugging expenses are related to plugging abandoned gas wells which CONSOL Energy does not own that are in front of the underground mining process. These wells have to be plugged in accordance with current safety regulations in order to mine through. CONSOL Energy has plugged more wells in 2008 than in 2007, which has contributed to increased supply costs. Gas well drilling ahead of mining, vents the gas from the coal seam which then allows for the longwall process to extract coal from a ventilated seam. CONSOL Energy drilled more wells ahead of mining in 2008 than in 2007 primarily due to Buchanan Mine being idled for half of 2007, as previously discussed.
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Higher fuel and explosive costs are due to the general increase of these commodities in the year-to-year comparison. The AMVEST surface locations were acquired on July 31, 2007. These surface locations are a large consumer of these products.
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Higher equipment maintenance costs are also attributable to the acquisition of AMVEST on July 31, 2007.
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These increases in supply costs were offset, in part, by expenses for self contained self rescuers which were purchased in 2007 in compliance with the Miner Act. There were fewer self-contained self rescuers purchased in 2008.
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Labor costs have increased $1.14 per ton sold due to the effects of wage increases at the union and non-union mines from labor contracts which began in 2007. These contracts call for specified hourly wage increases in each year of the contract. Labor also increased due to a higher number of employees in 2008 compared to 2007. This was somewhat due to the utilization of new work schedules requiring more manpower and operations trainees.
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Other postemployment benefit costs have increased $0.49 per ton sold primarily due to a change in the discount rate used to calculate the net periodic benefit costs. The weighted average discount rate for 2008 was 6.63% and was 6.00% in 2007.
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Combined Fund costs have increased $0.33 per ton sold due to the 2007 settlement with the Fund. In March 2007, CONSOL Energy entered into a settlement agreement with the Combined Fund that resolved all previous issues relating to the calculation of the payments. The total income, including interest, as a result of this settlement was approximately $33.4 million, of which approximately $28.1 million impacted cost of goods sold and other charges for produced coal.
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Health & Retirement costs have increased $0.25 per ton sold due to additional contributions required to be made into employee benefit funds in 2008 compared to 2007 as a result of the five-year labor agreement with the United Mine Workers of America (UMWA) that commenced January 1, 2007. The contribution increase over 2007 was $1.27 per UMWA hour worked.
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In-transit costs have increased $0.25 per ton sold. In-transit costs are costs to move coal from the point of extraction to the preparation plant in order for the coal to be processed for sale. These costs have increased due primarily to increased trucking expenses related to higher fuel costs as well as several locations operating in the current year that did not operate in 2007.
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Various other costs have increased $0.35 per ton sold due to various items that have occurred throughout both periods, none of which individually increased or decreased costs per ton sold.
Purchased coal cost of goods sold consists of costs from processing purchased coal in our preparation plants for blending purposes to meet customer coal specifications, coal purchased and sold directly to customers and costs for processing third-party coal in our preparation plants. The increase of $72 million in purchased coal cost of goods sold and other charges in 2008 was primarily due to higher volumes purchased.
Gas cost of goods sold and other charges increased due primarily to a 32.6% increase in volumes of produced gas sold and an 11.1% increase in unit costs of goods sold and other charges.
Average cost of goods sold and other charges per unit sold increased in the current year as a result of the following items:
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Fuel and power increased $0.08 per thousand cubic feet for both lifting and gathering combined. This increase was primarily due to additional compressors being placed in service along the existing gathering systems in order to flow gas more efficiently.
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Well closing costs increased $0.05 per thousand cubic feet in the year-to-year comparison. Well closing liabilities were adjusted in 2007 to reflect longer well lives than were previously estimated. This adjustment resulted in a reduction to expense. The adjustments to well closing liabilities were insignificant in 2008.
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Water disposal costs have increased $0.05 per thousand cubic feet due to additional volumes of water produced by CNX Gas wells in 2008 compared to 2007.
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Repairs and maintenance costs have increased $0.02 per thousand cubic feet due to higher material costs and higher contract labor costs.
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Compression expenses increased $0.03 per thousand cubic feet due to the additional compressors discussed above.
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Various other costs have also increased by $0.02 per thousand cubic feet for various items which occurred throughout both years, none of which were individually material.
Industrial supplies cost of goods sold increased $45 million primarily due to the July 2007 acquisition of Piping & Equipment, Inc. The increase was also related to additional volumes of goods sold and higher costs of good sold throughout 2008.
Closed and idle mine cost of goods sold decreased approximately $27 million in 2008 compared to 2007. The decrease was primarily due to $16 million of lower cost of goods sold and other charges at Shoemaker Mine. Shoemaker resumed longwall production in May 2008, but was idled throughout all of 2007. The decrease was
also related to updated engineering surveys related to mine closing, perpetual care water treatment and reclamation liabilities for closed and idled locations resulting in $23 million of expense in 2008 compared to $33 million of expense in 2007. The higher 2007 survey adjustments related primarily to perpetual water treatment changes in estimates of water flows and increased hydrated lime costs. Closed and idle mine cost of goods sold and other charges also increased $1 million due to various other charges which occurred throughout both periods, none of which were individually significant.
Other cost of goods sold decreased due to the following items:
In July 2007, production at the Buchanan Mine was suspended after several roof falls in previously mined areas damaged some of the ventilation controls inside the mine, requiring a general evacuation of the mine. In 2008, we have incurred approximately $17 million of cost of goods sold and other charges related to the Buchanan Mine event compared to $95 million in the prior year. The 2007 expense figure is net of $15 million related to insurance proceeds received as reimbursement for costs incurred under the policy. The mine resumed longwall production on March 17, 2008.
In 2007, CONSOL Energy agreed to a $6 million settlement for a contract violation with a customer.
The incentive compensation program is designed to increase compensation to eligible employees when CONSOL Energy reaches predetermined earnings targets and the employees reach predetermined performance targets. Incentive compensation expense decreased $2 million due to the level of earnings in comparison to the predetermined performance target in the year-to-year comparison.
The year ended December 31, 2008 includes expense of $7 million related to the Ward Transformer superfund site. In 2008, revised estimates of total costs related to this site were received. The revised estimates indicate an increase in costs to remediate the site. The year ended December 31, 2007 includes $5 million of expense related to this site. See “Note 25-Commitments and Contingencies” of Item 8, of the Consolidated Financial Statements for more details.
Accounts receivable securitization fees increased $3 million in the year-to-year comparison. Higher amounts have been drawn under this program throughout 2008 compared to 2007.
Expenses increased $3 million in 2008 related to a railroad spur acquired with the July 2007 acquisition of AMVEST. The increase was related to maintenance completed on the spur during the year. These expenses are offset with the related income reflected in other income.
Asset impairment expenses of $6 million were recognized in 2008 primarily related to loans made to, and options to purchase shares of common stock, with a startup company whose efforts are to commercialize
technology to burn waste coal with near zero emissions to generate power. Due mainly to the downturn in the economy, it is not probable that the company can repay these loans, or that the company will complete a public offering. Therefore, the asset values have been written down.
Stock-based compensation expense increased $10 million primarily as a result of additional awards granted to CONSOL Energy and CNX Gas employees in 2008. In addition, stock-based compensation expense increased due to changes in expected value of the cash payout related to the performance share units of CNX Gas.
Cost of goods sold and other charges includes $15 million in 2008 related to contracts with certain customers which were unable to take delivery of previously contracted coal tonnage. These customers have agreed to allow CONSOL Energy to sell the released tonnage, but require CONSOL Energy to split the incremental sales price over the original contract sales price evenly with them. The $15 million represents the additional sales price received for the tonnage sold that is owed to the original customer.
In 2008, CONSOL Energy agreed to buy-out sales contracts with several customers in order to release tons committed under lower priced contracts for sale to other customers at higher prices which resulted in $19 million of expense. No such agreements were made in 2007.
Terminal/River operation charges have increased $23 million in the year-to-year comparison due to increased fuel charges resulting from higher fuel prices and increased operating hours. Costs also have increased due to the acquisition of Tri-River Fleeting on October 3, 2007, as well as higher thru-put volumes in 2008.
Miscellaneous cost of goods sold and other charges increased $1 million due to various transactions throughout both periods, none of which were individually material.
Gas royalty interest costs represent the expenses related to the portion of production belonging to royalty interest owners sold by CNX Gas on their behalf. The increase in volumes and price relates to the volatility and contractual differences among leases, as well as the mix of average and index prices used in calculating royalties.
Purchased gas costs represent volumes of gas purchased from third-party producers, less our gathering and marketing fees, that we sell at market prices. Purchased gas volumes also include the impact of pipeline imbalances. The increase in cost of goods sold and other charges related to purchased gas represents overall price increases and contractual differences among customers in the year-to-year comparison.
Freight expense is based on weight of coal shipped, negotiated freight rates and method of transportation (i.e., rail, barge, truck, etc.) used for the customers to which CONSOL Energy contractually provides transportation services. Freight expense is the amount billed to customers for transportation costs incurred. Freight expense has increased in 2008 due primarily to freight associated with AMVEST, which was acquired on July 31, 2007. Freight expense has also increased due to higher freight rates being charged for exported tons. These increases in freight expense were offset, in part, by lower export tons shipped in 2008 compared to 2007. There were 7.0 million tons and 7.6 million tons of coal exported by CONSOL Energy in 2008 and 2007, respectively.
Selling, general and administrative costs have increased due to the following items:
Wages, salaries and related benefits increased $9 million in the year-to-year comparison due to additional staffing at our CNX Gas subsidiary, additional administrative staffing acquired in the July 2007 Piping & Equipment acquisition and various other increases in support staff throughout CONSOL Energy.
Association assessments have increased $6 million in the year-to-year comparison due primarily to CONSOL Energy’s participation in an industry organization which has launched a program related to the promotion of coal as an energy solution. CONSOL Energy did not participate in this organization in 2007. Also, CONSOL Energy participates in various associations and contributes to various charities in an effort to support the professions and the communities in which we do business. The level of funding made to these organizations varies from year-to-year.
Advertising and promotion expenses increased $2 million in 2008 due to various additional advertising and promotion agreements entered into throughout the current year.
Costs of professional, consulting and other purchased services decreased $2 million due to various administrative projects throughout both years, none of which are individually material.
Other selling, general and administrative costs increased $1 million due to various transactions that have occurred throughout both years, none of which are individually material.
Depreciation, depletion and amortization increased due to the following items:
The increase in coal depreciation, depletion and amortization was primarily attributable to additional expense related to the assets purchased in the July 2007 acquisition of AMVEST. The increase was also attributable to assets placed in service after December 31, 2007.
The increase in gas production related depreciation, depletion and amortization was primarily due to higher volumes combined with an increase in the units of production rates in the year-to-year comparison. These rates increased due to the higher proportion of capital assets placed in service versus the proportion of proved developed reserve additions. These rates are generally calculated using the net book value of assets at the end of the previous year divided by either proved or proved developed reserves.
Gathering depreciation, depletion and amortization is recorded using the straight-line method and increased due to additional assets placed in service after December 31, 2007.
Other depreciation increased $3 million due to various items placed in service after December 31, 2007, none of which were individually material.
Interest expense increased in 2008 compared to 2007 due to the following items:
Revolver interest expense increased $6 million due to the amounts drawn by CONSOL Energy and CNX Gas on the credit facility throughout 2008. There were no amounts drawn until August 2007 on this facility by CONSOL Energy. CNX Gas had no amounts drawn throughout all of 2007. These increases were offset, in part, by lower interest rates in the year-to-year comparison.
Interest on uncertain tax benefits decreased $1 million due primarily to the settlement of various uncertain tax positions due to receipt of the audit report related to the years 2004-2005.
Interest on capital leases decreased $1 million due to the planned payments made on these leases after December 31, 2007.
Interest on long-term secured notes decreased $1 million due to the planned June 2007 principal payment on our $45 million secured note.
Other interest increased $2 million due primarily to lower amounts of interest capitalized in 2008 compared to 2007. Capitalized interest was lower in 2008 because capital expenditures which qualify for interest capitalization were lower. These lower expenditures were primarily related to the Robinson Run overland belt which was placed in service in September 30, 2007.
On October 3, 2008 the Emergency Economic Stabilization Act of 2008 (the EESA Act) was signed into law. The EESA Act contains a section that authorizes certain coal producers and exporters who have filed a Black Lung Excise Tax (BLET) return on or after October 1, 1990, to request a refund of the BLET paid on export sales. The EESA Act requires that the U.S. Treasury refund a coal producer or exporter an amount equal to the BLET erroneously paid on export sales in prior years along with interest computed at the statutory rates applicable to overpayments. CONSOL Energy filed timely claims for refunds under the EESA Act of the BLET with the Internal Revenue Service in the amount of approximately $27 million. In addition, the estimated interest related to the BLET refunds expected to be received is approximately $32 million. In relation to this receivable, CONSOL Energy also recognized approximately $3 million of expense that will be owed to third parties upon collection of the refunds. The year ended December 31, 2007 included a $24 million charge related to the reversal of the receivable that had been recognized in previous quarters related to the BLET refund. The Federal Circuit court had ruled that the damage claim for BLET paid for the period 1991-1993 be repaid. The Government appealed a similar case to the U.S. Supreme Court. On December 3, 2007 the United States Supreme Court granted the Government’s appeal to hear the case. The Supreme Court’s appeal of the petition made collection of the refund no longer highly probable because of the adverse ruling by the Supreme Court during 2007 under the statute on which our claim for this period was based. Accordingly, CONSOL Energy reversed the BLET receivable it had previously recognized.
Taxes other than income increased primarily due to the following items:
Coal production taxes increased $18 million due to higher severance taxes and reclamation fee taxes attributable to the increase in average sales price for produced coal. Coal production taxes also increased due to higher tons produced in 2008 than 2007.
Gas production taxes increased $7 million due to higher severance taxes attributable to higher average sales prices for gas and higher gas sales volumes.
The $5 million increase in other coal taxes is primarily due to higher payroll related taxes and higher property taxes. Higher payroll related taxes were the result of additional employees in 2008 and higher wages paid as discussed in the cost of goods sold and other cost section. Higher property taxes were related to additional properties acquired in the July 31, 2007 AMVEST acquisition, as previously disclosed.
Other gas taxes have increased $2 million primarily related to payroll taxes and capital stock & franchise taxes due to the on-going growth of the company.
Other taxes decreased $1 million due to various transactions that occurred throughout both years, none of which were individually material.
Income Taxes
CONSOL Energy’s effective tax rate is sensitive to changes in the relationship between pre-tax earnings and percentage depletion. The proportion of coal pre-tax earnings and gas pre-tax earnings also impacts the benefit of percentage depletion on the effective tax rate. See “Note 6-Income Taxes” in Item 8, Consolidated Financial Statements of this Form 10-K.
Noncontrolling Interest
Noncontrolling interest represents 18.3% of CNX Gas net income which CONSOL Energy did not own through September 30, 2008, 18.0% for October 2008, 16.9% for November 2008 and 16.7% for December 2008. The noncontrolling interest in CNX Gas has been changing due to the share repurchase program that was approved by the CONSOL Energy Board of Directors on October 21, 2008.
Critical Accounting Policies
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make judgments, estimates and assumptions that affect reported amounts of assets and liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities in the consolidated financial statements and at the date of the financial statements. Note 1 of the Notes to the Audited Consolidated Financial Statements in this Annual Report on Form 10-K describes the significant accounting policies and methods used in the preparation of the Consolidated Financial Statements. On an on-going basis, we evaluate our estimates. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making the judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from those estimates upon subsequent resolution of identified matters. Management believes that the estimates utilized are reasonable. The following critical accounting policies are materially impacted by judgments, assumptions and estimates used in the preparation of the Consolidated Financial Statements.
Other Post Employment Benefits
Certain subsidiaries of CONSOL Energy provide medical and life insurance benefits to retired employees not covered by the Coal Industry Retiree Health Benefit Act of 1992. The medical plans contain certain cost sharing and containment features, such as deductibles, coinsurance, health care networks and coordination with Medicare. For salaried employees hired before January 1, 2007, the eligibility requirement is either age 55 with 20 years of service or age 62 with 15 years of service. Also, salaried employees and retirees contribute a target of 20% of the medical plan operating costs. Contributions may be higher, dependent on either years of service or a combination of age and years of service at retirement. Prospective annual cost increases of up to 6% will be shared by CONSOL Energy and the participants based on their age and years of service at retirement. Annual cost increases in excess of 6% will be the responsibility of the participant. Any salaried or non-represented hourly employees that were hired or rehired effective January 1, 2007 or later will not become eligible for retiree health benefits. In lieu of traditional retiree health coverage, if certain eligibility requirements are met, these employees will receive a retiree medical spending allowance of $2,250 per year for each year of service at retirement. Newly employed inexperienced employees represented by the United Mine Workers of America (UMWA), hired after January 1, 2007, will not be eligible to receive retiree benefits. In lieu of these benefits, these employees will receive a defined contribution benefit of $1 per each hour worked.
After our review, various actuarial assumptions, including discount rate, expected trend in health care costs, average remaining service period, average remaining life expectancy, per capita costs and participation level in each future year are used by our independent actuary to estimate the cost and benefit obligations for our retiree health plans. Most assumptions used in 2009 have not differed materially from the prior year actual experience. Expected trend in health care cost assumptions have been changed since the prior year. The initial expected trend in health care costs at this year’s measurement date, which was December 31, 2009, was 8.74% compared to a prior year expected 2009 trend in health care cost of 9.6%. In addition, the year the ultimate trend rate is reached was extended from 5.0% in 2015 to 4.50% in 2023. A 1.0% decrease in the health care trend rate would decrease interest and service cost for 2009 by approximately $17.0 million. A 1.0% increase in the health care trend rate would increase the interest and service cost by approximately $19.9 million. The discount rate is also determined each year at the measurement date. The discount rate is estimated by utilizing a corporate yield curve model developed from corporate bond data using only bonds rated Aa by Moody’s as of the measurement date. All future post employment benefit expected payments were discounted using a spot rate yield curve as of December 31, 2009. The appropriate discount rate was then selected from resulting discounted cash flows. For the years ended December 31, 2009 and 2008, the discount rate used to calculate the period end liability and the following year’s expense was 5.87% and 6.20%, respectively. A 0.25% increase in the discount rate would have decreased 2009 net periodic postretirement benefit costs by approximately $3.8 million. A 0.25% decrease in the discount rate would have increased 2009 net periodic postretirement benefit costs by approximately $3.8 million. Deferred gains and losses are primarily due to historical changes in the discount rate and medical cost inflation
differing from expectations in prior years. Changes to interest rates for the rates of returns on instruments that could be used to settle the actuarially determined plan obligations introduce substantial volatility to our costs. Accumulated actuarial gains or losses in excess of a pre-established corridor are amortized on a straight-line basis over the expected future service of active salary and non-represented employees to their assumed retirement age. At December 31, 2009 the average remaining service period is approximately 11 years for our non-represented plans. Accumulated actuarial gains or losses in excess of a pre-established corridor are amortized on a straight-line basis over the expected remaining life of our retired UMWA population. The average remaining service period of this population is not used for amortization purposes because the majority of the UMWA population of our plan is retired. At December 31, 2009, the average remaining life expectancy of our retired UMWA population used to calculate the following year’s expense is approximately 13 years.
The weighted average per capita costs used to value the December 31, 2009 Other Postretirement Benefit liability was 4.84% less than expected based on our trend assumption. This was due to more favorable experience during the year. If the actual change in per capita cost of medical services or other postretirement benefits are significantly greater or less than the projected trend rates, the per capita cost assumption would need to be adjusted, which could have a significant effect on the costs and liabilities recognized in the financial statements.
Significant increases in health and prescription drug costs for represented hourly retirees could have a material adverse effect on CONSOL Energy’s operating cash flow. However, the effect on CONSOL Energy’s cash flow from operations for salaried employees is limited to approximately 6% of the previous year’s medical cost for salaried employees due to the cost sharing provision in the benefit plan.
The estimated liability recognized in the December 31, 2009 financial statements was $2.8 billion. For the year ended December 31, 2009, we paid approximately $155.9 million for Other Postretirement Benefits, all of which were paid from operating cash flow. Our obligations with respect to these liabilities are unfunded at December 31, 2009. CONSOL Energy does not expect to contribute to the other postretirement plan in 2010. We intend to pay benefit claims as they are due.
Salaried Pensions
CONSOL Energy has non-contributory defined benefit retirement plans covering substantially all employees not covered by multi-employer plans. The benefits for these plans are based primarily on years of service and employee’s pay near retirement. CONSOL Energy’s salaried plan allows for lump-sum distributions of benefits earned up until December 31, 2005, at the employees’ election. The Restoration Plan was frozen effective December 31, 2006 and was replaced prospectively with the CONSOL Energy Supplemental Retirement Plan. CONSOL Energy’s Restoration Plan allows only for lump-sum distributions earned up until December 31, 2006. Effective September 8, 2009, the Supplemental Retirement Plan was amended to include employees of CNX Gas.
In March of 2009 the CNX Gas defined benefit retirement plan was merged into the Consol Energy’s non-contributory defined benefit retirement plan. This change did not impact the benefits for employees of CNX Gas, an 83.3% owned subsidiary. CNX Gas employees hired after January 1, 2007, are not eligible to participate in this non-contributory defined benefit retirement plan. In lieu of participation in the non-contributory defined benefit plan, these employees began receiving an additional 3% company contribution into their defined contribution plan. CNX Gas employees who were hired prior to December 31, 2005 or who were employees of CONSOL Energy prior to this date were given a one-time opportunity to elect to remain in the defined benefit plan or opt to freeze their service accruals and participate in the additional 3% company contribution into their defined contribution plan.
Our independent actuaries calculate the actuarial present value of the estimated retirement obligation based on assumptions including rates of compensation, mortality rates, retirement age and interest rates. For the year ended December 31, 2009, compensation increases are assumed to range from 3% to 8% depending on age and
job classification. The discount rate is determined each year at the measurement date. The discount rate is estimated by utilizing a corporate yield curve model developed from corporate bond data using only bonds rated Aa by Moody’s as of the measurement date. All expected benefit payments from the CONSOL Energy retirement plan were discounted using a spot rate yield curve as of December 31, 2009. The appropriate equivalent discount rate was then selected for the resulting discounted pension cash flows. For the years ended December 31, 2009 and 2008, the discount rate used to calculate the period end liability and the following year’s expense was 5.79% and 6.28%, respectively. A 0.25% increase in the discount rate would have decreased the 2009 net periodic pension cost by $0.7 million. A 0.25% decrease in the discount rate would have increased the 2009 net periodic pension cost by $0.7 million. Deferred gains and losses are primarily due to historical changes in the discount rate and earnings on assets differing from expectations in prior years. At December 31, 2009 the average remaining service period is approximately 10 years. Changes to any of these assumptions introduce substantial volatility to our costs.
The market related asset value is derived by taking the cost value of assets as of December 31, 2009 and multiplying it by the average 36-month ratio of the market value of assets to the cost value of assets. CONSOL Energy’s pension plan weighted average asset allocations at December 31, 2009 consisted of 61% equity securities and 39% debt securities. The volatile economic environment and rapid deterioration in the equity markets have caused investment income and the value of investment assets held in our pension trust to decline and lose value. As a result, we may be required to increase the amount of cash contributions we make into the pension trust.
The estimated liability recognized in the December 31, 2009 financial statements was $192.0 million. For the year ended December 31, 2009, we contributed approximately $67.7 million for defined benefit retirement plans other than multi-employer plans. Our obligations with respect to these liabilities are partially funded at December 31, 2009. CONSOL Energy does expect to contribute to the defined benefit retirement plans during 2010. We intend to contribute an amount that will avoid benefit restrictions for the following plan year.
Workers’ Compensation and Coal Workers’ Pneumoconiosis
Workers’ compensation is a system by which individuals who sustain employment related physical injuries or some type of occupational diseases are compensated for their disabilities, medical costs, and on some occasions, for the costs of their rehabilitation. Workers’ compensation will also compensate the survivors of workers who suffer employment related deaths. The workers’ compensation laws are administered by state agencies with each state having its own set of rules and regulations regarding compensation that is owed to an employee that is injured in the course of employment. CONSOL Energy records an actuarially calculated liability, which is determined using various assumptions, including discount rate, future healthcare cost trends, benefit duration and recurrence of injuries. The discount rate is determined each year at the measurement date. The discount rate is estimated by utilizing a corporate yield curve model developed from corporate bond data using only bonds rated Aa by Moody’s as of the measurement date. All future workers’ compensation expected benefit payments were discounted using a spot rate yield curve as of December 31, 2009. The appropriate equivalent discount rate was then selected from the resulting discounted workers’ compensation cash flows. For the years ended December 31, 2009 and 2008, the discount rate used to calculate the period end liability and the following year’s expense was 5.55% and 5.90%, respectively. A 0.25% increase or decrease in the discount rate would not have materially changed the 2009 workers’ compensation expense. Deferred gains and losses are primarily due to historical changes in the discount rates, several years of favorable claims experience, various favorable claims experience, various favorable state legislation changes and an overall lower incident rate than our assumptions. Accumulated actuarial gains or losses are amortized on a straight-line basis over the expected future benefit duration of current claimants. At December 31, 2009, the average expected benefit duration for this group is approximately 9 years. The estimated liability recognized in the financial statements at December 31, 2009 was approximately $179.3 million. CONSOL Energy’s policy has been to provide for workers’ compensation benefits from operating cash flow. For the year ended December 31, 2009, we made payments for workers’ compensation benefits and other related fees of approximately $37.6 million, all of which was paid from operating cash flow. Our obligations with respect to these liabilities are unfunded at December 31, 2009.
CONSOL Energy is responsible under the Federal Coal Mine Health and Safety Act of 1969, as amended, for medical and disability benefits to employees and their dependents resulting from occurrences of coal workers’ pneumoconiosis disease. CONSOL Energy is also responsible under various state statutes for pneumoconiosis benefits. After our review, our independent actuaries calculate the actuarial present value of the estimated pneumoconiosis obligation based on assumptions regarding disability incidence, medical costs, mortality, death benefits, dependents and discount rates. The discount rate is determined each year at the measurement date. The discount rate is estimated by utilizing a corporate yield curve model developed from corporate bond data using only bonds rated Aa by Moody’s as of the measurement date. All future coal workers’ pneumoconiosis expected benefit payments were discounted using a spot rate yield curve at December 31, 2009. The appropriate equivalent discount rate was then selected from the resulting discounted coal workers’ pneumoconiosis cash flows. For the years ended December 31, 2009 and 2008, the discount rate used to calculate the period end liability and the following year’s expense was 5.84% and 6.23%, respectively. A 0.25% increase in the discount rate would have decreased 2009 coal workers’ pneumoconiosis expense by $0.7 million. A 0.25% decrease in the discount rate would have increased 2009 coal workers’ pneumoconiosis by $0.7 million. Actuarial gains associated with coal workers’ pneumoconiosis have resulted from numerous legislative changes over many years which have resulted in lower approval rates for filed claims than our assumptions originally reflected. Actuarial gains have also resulted from lower incident rates and lower severity of claims filed than our assumption originally reflected. The estimated liability recognized in the financial statements at December 31, 2009 was $194.6 million. For the year ended December 31, 2009, we paid coal workers’ pneumoconiosis benefits of approximately $10.7 million, all of which was paid from operating cash flow. Our obligations with respect to these liabilities are unfunded at December 31, 2009.
Reclamation, Mine Closure and Gas Well Closing Obligations
The Surface Mining Control and Reclamation Act established operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining. CONSOL Energy accrues for the costs of current mine disturbance and final mine and gas well closure, including the cost of treating mine water discharge where necessary. Estimates of our total reclamation, mine-closing liabilities, and gas well closing which are based upon permit requirements and CONSOL Energy engineering expertise related to these requirements, including the current portion, were approximately $533.2 million at December 31, 2009. This liability is reviewed annually by CONSOL Energy management and engineers. The estimated liability can significantly change if actual costs vary from assumptions or if governmental regulations change significantly.
Accounting for Asset Retirement Obligations requires that the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Asset retirement obligations primarily relate to the closure of mines and gas wells and the reclamation of land upon exhaustion of coal and gas reserves. Changes in the variables used to calculate the liabilities can have a significant effect on the mine closing, reclamation and gas well closing liabilities. The amounts of assets and liabilities recorded are dependent upon a number of variables, including the estimated future retirement costs, estimated proven reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rate.
Accounting for Asset Retirement Obligations also requires depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time. The depreciation will generally be determined on a units-of-production basis, whereas the accretion to be recognized will escalate over the life of the producing assets, typically as production declines.
Income Taxes
Deferred tax assets and liabilities are recognized using enacted tax rates for the effect of temporary differences between the book and tax basis of recorded assets and liabilities. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion of the deferred tax asset will not be realized.
All available evidence, both positive and negative, must be considered in determining the need for a valuation allowance. At December 31, 2009, CONSOL Energy has deferred tax assets in excess of deferred tax liabilities of approximately $498.7 million. The deferred tax assets are evaluated periodically to determine if a valuation allowance is necessary.
Deferred tax valuation allowances increased $0.7 million in the year ended December 31, 2009 due to various transactions that occurred throughout 2009, none of which were individually material. Valuation allowances on certain net operating loss carry forwards were not released during the year due to negative evidence outweighing positive evidence indicating that these benefits will not be utilized in future years. CONSOL Energy continues to report a deferred tax asset of approximately $37.1 million relating to its state net operating loss carry forwards subject to a full valuation allowance. A review of positive and negative evidence regarding these benefits, primarily the history of financial and tax losses on a separate company basis, concluded that a full valuation allowance was warranted. The net operating loss carry forwards expire at various times from 2010 to 2027. A valuation allowance of $24.5 million has also been recorded against the state deferred tax asset attributable to future tax deductible differences for certain subsidiaries with histories of financial and tax losses. Management will continue to assess the realization of deferred tax assets attributable to state net operating loss carry forwards and future tax deductible differences based upon updated income forecast data and the feasibility of future tax planning strategies, and may record adjustments to valuation allowances against these deferred tax assets in future periods as appropriate that could materially impact net income.
CONSOL Energy evaluates all tax positions taken on the state and federal tax filings to determine if the position is more likely than not to be sustained upon examination. For positions that meet the more likely than not to be sustained criteria, an evaluation to determine the largest amount of benefit, determined on a cumulative probability basis that is more likely than not to be realized upon ultimate settlement is determined. A previously recognized tax position is derecognized when it is subsequently determined that a tax position no longer meets the more likely than not threshold to be sustained. The evaluation of the sustainability of a tax position and the probable amount that is more likely than not is based on judgment, historical experience and on various other assumptions that we believe are reasonable under the circumstances. The results of these estimates, that are not readily apparent from other sources, form the basis for recognizing an uncertain tax liability. Actual results could differ from those estimates upon subsequent resolution of identified matters. Estimates of our uncertain tax liabilities, including interest and the current portion, were approximately $65.3 million at December 31, 2009.
Stock Based Compensation
As of December 31, 2009, we have issued three types of share based payment awards: options, restricted stock units, and performance share units. The Black-Scholes option pricing model is used to determine fair value of stock options at the grant date. Various inputs are utilized in the Black-Scholes pricing model, such as:
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stock price on measurement date,
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exercise price defined in the award,
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expected dividend yield based on historical trend of dividend payouts,
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risk-free interest rate based on a zero-coupon treasury bond rate,
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expected term based on historical grant and exercise behavior, and
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expected volatility based on historic and implied stock price volatility of CONSOL Energy stock and public peer group stock.
These factors can significantly impact the value of stock options expense recognized over the requisite service period of option holders.
The fair value of each restricted stock unit awarded is equivalent to the closing market price of a share of our company’s stock on the date of the grant. The fair value of each performance share unit is determined by the underlying share price of our company stock on the date of the grant and management’s estimate of the probability that the performance conditions required for vesting will be achieved.
As of December 31, 2009, $24.6 million of total unrecognized compensation cost related to unvested awards is expected to be recognized over a weighted-average period of 1.57 years. See Note 18 in the Notes to the Audited Consolidated Financial Statements in Item 8 in this Form 10-K for more information.
Contingencies
CONSOL Energy is currently involved in certain legal proceedings. We have accrued our estimate of the probable costs for the resolution of these claims. This estimate has been developed in consultation with legal counsel involved in the defense of these matters and is based upon an analysis of potential results, assuming a combination of litigation and settlement strategies. Future results of operations for any particular quarter or annual period could be materially affected by changes in our assumptions or the outcome of these proceedings. See Note 24 in the Notes to the Audited Consolidated Financial Statements in Item 8 in this Form 10-K for more information.
Successful Efforts Accounting
We use the successful efforts method to account for our gas exploration and production activities. Under this method, cost of property acquisitions, successful exploratory wells, development wells and related support equipment and facilities are capitalized. Costs of unsuccessful exploratory wells are expensed when such wells are determined to be non-productive, or if the determination cannot be made after finding sufficient quantities of reserves to continue evaluating the viability of the project. We use this accounting policy instead of the “full cost” method because it provides a more timely accounting of the success or failure of our gas exploration and production activities.
Derivative Instruments
CNX Gas enters into financial derivative instruments to manage exposure to natural gas and oil price volatility. We measure every derivative instrument at fair value and record them on the balance sheet as either an asset or liability. Changes in fair value of derivatives are recorded currently in earnings unless special hedge accounting criteria are met. For derivatives designated as fair value hedges, the changes in fair value of both the derivative instrument and the hedged item are recorded in earnings. For derivatives designated as cash flow hedges, the effective portions of changes in fair value of the derivative are reported in other comprehensive income or loss and reclassified into earnings in the same period or periods which the forecasted transaction affects earnings. The ineffective portions of hedges are recognized in earnings in the current year. CNX Gas currently utilizes only cash flow hedges that are considered highly effective.
CNX Gas formally assesses, both at inception of the hedge and on an ongoing basis, whether each derivative is highly effective in offsetting changes in fair values or cash flows of the hedge item. If it is determined that a derivative is not highly effective as a hedge or if a derivative ceases to be a highly effective hedge, CNX Gas will discontinue hedge accounting prospectively.
Coal and Gas Reserve Values
There are numerous uncertainties inherent in estimating quantities and values of economically recoverable coal and gas reserves, including many factors beyond our control. As a result, estimates of economically recoverable coal and gas reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our staff. Our coal
reserves are periodically reviewed by an independent third party consultant. Our gas reserves have been reviewed by independent experts. Some of the factors and assumptions which impact economically recoverable reserve estimates include:
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geological conditions;
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historical production from the area compared with production from other producing areas;
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the assumed effects of regulations and taxes by governmental agencies;
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assumptions governing future prices; and
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future operating costs.
Each of these factors may in fact vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of the economically recoverable quantities of coal and gas attributable to a particular group of properties, and classifications of these reserves based on risk of recovery and estimates of future net cash flows, may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and these variances may be material. See “Risk Factors” in Item 1A of this report for a discussion of the uncertainties in estimating our reserves.
Liquidity and Capital Resources
CONSOL Energy generally has satisfied our working capital requirements and funded our capital expenditures and debt service obligations with cash generated from operations and proceeds from borrowings. We utilize a $1 billion senior secured credit facility which expires in 2012. The facility is secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries and collateral is shared equally and ratably with the holders of CONSOL Energy Inc. 7.875% bonds maturing in June 2012. The agreement provides for the release of collateral at the request of CONSOL Energy upon the achievement of certain credit ratings. Fees and interest rate spreads are based on a ratio of financial covenant debt to twelve-month trailing earnings before interest, taxes, depreciation, depletion and amortization (EBITDA), measured quarterly. The facility includes a minimum interest coverage ratio covenant of no less than 4.50 to 1.00, measured quarterly. The interest coverage ratio was 24.78 to 1.00 at December 31, 2009. The facility also includes a maximum leverage ratio covenant of not more than 3.25 to 1.00, measured quarterly. The leverage ratio was 0.87 to 1.00 at December 31, 2009. Affirmative and negative covenants in the facility limit our ability to dispose of assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends and merge with another corporation. At December 31, 2009, the facility had approximately $415 million drawn and $268 million of letters of credit outstanding, leaving $317 million of unused capacity. From time to time, CONSOL Energy is required to post financial assurances to satisfy contractual and other requirements generated in the normal course of business. Some of these assurances are posted to comply with federal, state or other government agencies statutes and regulations. We sometimes use letters of credit to satisfy these requirements and these letters of credit reduce our borrowing facility capacity.
The Pennsylvania Department of Environmental Protection (PA DEP) and CONSOL Energy have executed a Consent Order and Agreement (the Agreement) that addresses financial assurance required by the State for CONSOL Energy’s Pennsylvania mine water treatment facilities for mines closed prior to August 1977. The Agreement requires the company to post approximately $34 million of financial assurance over a 10-year time frame. CONSOL Energy is evaluating use of the credit facility and other alternative sources to satisfy these requirements.
CONSOL Energy and certain of our U.S. subsidiaries also participate in a receivables securitization facility for the sale on a continuous basis of eligible trade accounts receivable that will provide, on a revolving basis, up to $165 million of short-term funding or letters of credit. CONSOL Energy formed CNX Funding Corporation, a wholly owned, special purpose, bankruptcy-remote subsidiary, for the sole purpose of buying and selling eligible trade receivables generated by certain subsidiaries of CONSOL Energy. Under the receivables facility, CONSOL
Energy and certain subsidiaries, irrevocably and without recourse, sell all of their eligible trade accounts receivable to CNX Funding Corporation. CNX Funding Corporation then sells, on a revolving basis, an undivided percentage interest in the pool of eligible trade accounts receivable to financial institutions and their affiliates, while maintaining a subordinated interest in a portion of the trade receivables. CONSOL Energy has agreed to continue servicing the sold receivables for the financial institutions for a fee based upon market rates for similar services. The cost of funds is consistent with commercial paper rates plus a charge for administrative services paid to the financial institution. At December 31, 2009, eligible accounts receivable totaled approximately $151 million. There was $101 million of subordinate retained interest at December 31, 2009. Accounts receivable totaling $50 million were removed from the consolidated balance sheet at December 31, 2009. There were no letters of credit outstanding against the facility at December 31, 2009.
CNX Gas, an 83.3% consolidated subsidiary of CONSOL Energy, utilizes a revolving credit facility providing an initial aggregate outstanding principal amount of up to $200 million, including borrowings and letters of credit, which expires in October 2010. CNX Gas can request an additional $100 million increase in the aggregate outstanding principal amount. The agreement contains a negative pledge provision, pursuant to which CNX Gas assets cannot be used to secure other obligations. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Covenants in the facility limit CNX Gas’ ability to dispose of assets, make investments, purchase or redeem CNX Gas stock, pay dividends and merge with another corporation. This facility includes a leverage ratio covenant of not more than 3.00 to 1.00, measured quarterly. This ratio was 0.38 to 1.00 at December 31, 2009. The facility also includes an interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. This ratio was 68.17 to 1.00 at December 31, 2009. At December 31, 2009, this facility had approximately $15 million of letters of credit issued and had approximately $58 million of outstanding borrowings, leaving approximately $127 million of unused capacity. As a result of the credit agreement, CNX Gas and their subsidiaries executed a Supplemental Indenture on October 21, 2005, guaranteeing CONSOL Energy’s 7.875% bonds.
Uncertainty in the financial markets brings additional potential risks to CONSOL Energy. The risks include declines in our stock price, less availability and higher costs of additional credit streams, potential counterparty defaults, and further commercial bank failures. Although the majority of the financial institutions in our bank group appear to be strong, there are some that have been and could be considered take-over candidates. We have no indication that any such transactions would impact our current credit facility; however, the possibility does exist. Financial market disruptions may impact our collection of trade receivables. CONSOL Energy constantly monitors the creditworthiness of our customers. We believe that our current group of customers are sound and represent no abnormal business risk.
CONSOL Energy believes that cash generated from operations and our borrowing capacity will be sufficient to meet our working capital requirements, anticipated capital expenditures (other than major acquisitions), scheduled debt payments, anticipated dividend payments and to provide required letters of credit. Nevertheless, the ability of CONSOL Energy to satisfy our working capital requirements, debt service obligations, to fund planned capital expenditures or pay dividends will depend upon future operating performance, which will be affected by prevailing economic conditions in the coal and gas industries and other financial and business factors, some of which are beyond CONSOL Energy’s control.
In order to manage the market risk exposure of volatile natural gas prices in the future, CONSOL Energy enters into various physical gas supply transactions with both gas marketers and end users for terms varying in length. CONSOL Energy has also entered into various gas swap transactions that qualify as financial cash flow hedge, which exist parallel to the underlying physical transactions. The fair value of these contracts was an asset of $117 million at December 31, 2009. The ineffective portion of these contracts was insignificant to earnings in the year ended December 31, 2009. Hedge counterparties consists of commercial banks who participate in the revolving credit facility. No issues related to our hedge agreements have been encountered to date.
CONSOL Energy frequently evaluates potential acquisitions. CONSOL Energy has funded acquisitions primarily with cash generated from operations and a variety of other sources, depending on the size of the
transaction, including debt financing. There can be no assurance that additional capital resources, including debt financing, will be available to CONSOL Energy on terms which CONSOL Energy finds acceptable, or at all.
Cash Flows (in millions)
Cash flows provided by operating activities changed primarily due to the following items:
•
Operating cash flows were lower in 2009 due to $115 million of repayments on the accounts receivable securitization program compared to receipt of $40 million of proceeds in 2008.
•
Operating cash flow in 2008 included a $75 million cash receipt from insurance carriers related to the Buchanan mine incident, as previously disclosed.
•
Operating cash flows were lower in 2009 by approximately $26 million due to coal inventories. Coal inventories increased 1.5 million tons in 2009. Coal inventories increased 462 thousand tons in 2008.
•
Operating cash flow increased in 2009 due to higher net income in the year-to-year comparison. Net income included higher amounts of depreciation, depletion and amortization in 2009 as discussed in the year-to-year operation analysis. Operating cash flows also increased due to various other changes in operating assets, operating liabilities, other assets and other liabilities which occurred throughout both years.
•
Operating cash flow increased in 2009 as the result of CONSOL Energy receiving the total principal and related interest for the Black Lung Excise Tax Refund, a total of $55 million, net of amounts paid to third parties.
Net cash used in investing activities changed primarily due to the following items:
•
Total capital expenditures decreased $142 million to $920 million in 2009 compared to $1,062 million in 2008. Capital expenditures for gas decreased $240 million due to the slow-down of the drilling program related to the weak economic environment and $36 million expended in 2008 for the acquisition of the remaining portion of Knox Energy, offset in part, by a $56 million increase due to Marcellus drilling activity in Northern Appalachia. Capital expenditures for coal and other activities increased $98 million due to various projects including the continued work at Shoemaker mine to replace the track haulage with belt haulage, the face extension work at Bailey mine, the purchase of longwall shields which were sold and leased back, and the Buchanan water handling system.
•
CONSOL Energy purchased $67 million of CNX Gas common stock on the open market during 2008. No purchases of CNX Gas stock were made during 2009.
•
Proceeds from the sale of assets were $70 million in 2009 compared to $28 million in 2008. Proceeds in 2009 were primarily related to the sale of longwall equipment that was subsequently leased back. Proceeds in 2008 were primarily related to the sale of the Mill Creek Mine.
Net cash (used in) provided by financing activities changed primarily due to the following items:
•
In 2009, CONSOL Energy paid outstanding borrowings of $70 million to the revolving credit facility. In 2008, CONSOL Energy received approximately $237 million of proceeds from the revolving credit facility.
•
In 2009, CONSOL Energy’s 83.3% owned subsidiary, CNX Gas, repaid outstanding borrowings of $15 million to the revolving credit facility. In 2008, CNX Gas received proceeds of approximately $73 million from its revolving credit facility.
•
CONSOL Energy repurchased $98 million of its common stock on the open market under the share repurchase program in 2008. No repurchases of common stock were made in 2009.
•
Tax benefits from stock-based compensation resulted in approximately $3 million of cash inflows in 2009. These benefits resulted in a cash inflow of approximately $22 million in 2008.
•
In 2009, $3 million of cash inflows were received related to the issuance of CONSOL Energy Treasury Stock compared to $15 million in 2008.
The following is a summary of our significant contractual obligations at December 31, 2009 (in thousands):
Payments due by Year
(a) Long-term liabilities include other post-employment benefits, work-related injuries and illnesses, mine reclamation and closure and other long-term liability costs. Estimated salaried retirement contributions required to meet minimum funding standards under ERISA are excluded from the pay-out table due to the uncertainty regarding amounts to be contributed. Estimated 2010 contributions are expected to approximate $64 million.
(b) The significant obligation table does not include obligations to taxing authorities due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.
Debt
At December 31, 2009, CONSOL Energy had total long-term debt of $468 million outstanding, including the current portion of long-term debt of $45 million. This long-term debt consisted of:
•
An aggregate principal amount of $249 million of 7.875% notes ($250 million of 7.875% notes due in March 2012, net of $1 million unamortized debt discount). The notes were issued at 99.174% of the principal amount. Interest on the notes is payable March 1 and September 1 of each year. Payment of the principal and premium, if any, and interest on the notes are guaranteed by most of CONSOL Energy’s subsidiaries. The notes are senior secured obligations and rank equally with all other secured indebtedness of the guarantors;
•
An aggregate principal amount of $31 million and $72 million of industrial revenue bonds which were issued to finance the Baltimore Port facility and bear interest at 6.50% per annum and mature in December 2010 and October 2011;
•
$36 million in advance royalty commitments with an average interest rate of 10.4% per annum;
•
An aggregate principal amount of $15 million on a variable rate note that bears interest at 6.10% at December 31, 2009. This note was incurred by a variable interest entity that is fully consolidated in which CONSOL Energy holds no ownership interest;
•
An aggregate principal amount of $65 million of capital leases with a weighted average interest rate of 6.82% per annum;
At December 31, 2009, CONSOL Energy also had $415 million of aggregate principal amounts of outstanding borrowings and approximately $268 million of letters of credit outstanding under the $1 billion senior secured revolving credit facility.
At December 31, 2009, CNX Gas, an 83.3% owned subsidiary, had $58 million of aggregate principal amounts of outstanding borrowings and approximately $15 million of letters of credit outstanding under its $200 million revolving credit facility.
Total Equity and Dividends
CONSOL Energy had total equity of $2,024 million at December 31, 2009 and $1,674 million at December 31, 2008. Total equity increased primarily due to net income for the year ended December 31, 2009 and amortization of stock-based compensation awards. These increases were offset by changes in the actuarial long-term liabilities, changes in cash flow hedging, the declaration of dividends, and the issuance of treasury stock. See Consolidated Statements of Stockholders’ Equity in the Audited Consolidated Financial Statements in Item 8 of this Form 10-K.
Total equity also changed due to the implementation of the Noncontrolling Interest Topic of the Financial Accounting Standards Board Accounting Standards Codification. This topic required minority interest to be recharacterized as noncontrolling interests, and classified as a component of equity for all periods presented as of January 1, 2009.
In September 2008, CONSOL Energy announced a share repurchase program of up to $500 million of the company’s common stock during a 24-month period beginning in September 2008. The share repurchase plan will be used from time-to-time depending on a number of factors including: current market conditions; the company’s financial outlook; business conditions, including cash flows and internal capital requirements; as well as alternative investment options. No shares have been purchased during 2009. As of December 31, 2008, we had purchased a total of 2,741,300 shares at an average price of $35.59 per share under this program.
Dividend information for the current year is as follows:
The declaration and payment of dividends by CONSOL Energy is subject to the discretion of CONSOL Energy’s Board of Directors, and no assurance can be given that CONSOL Energy will pay dividends in the future. CONSOL Energy’s Board of Directors determines whether dividends will be paid quarterly. The determination to pay dividends will depend upon, among other things, general business conditions, CONSOL Energy’s financial results, contractual and legal restrictions regarding the payment of dividends by CONSOL Energy, planned investments by CONSOL Energy and such other factors as the Board of Directors deems relevant. Our credit facility limits our ability to pay dividends when our leverage ratio covenant is 2.50 to 1.00 or more or our availability is less than $100 million. The leverage ratio was 0.87 to 1.00 and our availability was approximately $317 million at December 31, 2009. The credit facility does not permit dividend payments in the event of default. There were no defaults in the year ended December 31, 2009.
Off-Balance Sheet Transactions
CONSOL Energy does not maintain any off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on CONSOL Energy’s financial condition, changes in financial condition, revenues or expenses, results of
operations, liquidity, capital expenditures or capital resources which are not disclosed in the Notes to the Consolidated Financial Statements. CONSOL Energy participates in various multi-employer benefit plans such as the United Mine Workers’ of America (UMWA) 1974 Pension Plan, the UMWA Combined Benefit Fund and the UMWA 1993 Benefit Plan which generally accepted accounting principles recognize on a pay as you go basis. These benefit arrangements may result in additional liabilities that are not recognized on the balance sheet at December 31, 2009. The various multi-employer benefit plans are discussed in Note 17-Other Employee Benefit Plans in Item 8 of this Form 10-K. CONSOL Energy also uses a combination of surety bonds, corporate guarantees and letters of credit to secure our financial obligations for employee-related, environmental, deliveries and various other items which are not reflected on the balance sheet at December 31, 2009. Management believes these items will expire without being funded. See Note 24-Commitments and Contingent Liabilities in Item 8 of this Form 10-K.
Recent Accounting Pronouncements
In June 2009, the FASB issued authoritative guidance on the consolidation of variable interest entities, which is effective for CONSOL beginning July 1, 2010. The new guidance requires revised evaluations of whether entities represent variable interest entities, ongoing assessments of control over such entities, and additional disclosures for variable interests. We believe adoption of this new guidance will not have material impact on CONSOL’s financial statements.
In June 2009, the FASB issued accounting guidance regarding the accounting for transfers of financial assets that is designed to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial statements about a transfer of financial assets; the effects of a transfer on its financial position, financial performance, and cash flows; and a transferor’s continuing involvement, if any, in transferred financial assets. The guidance enhances the information provided to financial statement users to provide greater transparency about transfers of financial assets and a transferor’s continuing involvement, if any, with transferred financial assets. The guidance requires enhanced disclosures about the risks that a transferor continues to be exposed to because of its continuing involvement in transferred financial assets. This guidance is effective for an entity’s first annual reporting period after November 15, 2009 and is not eligible for early adoption. Management believes that this guidance will result in the securitization facility transactions being reclassified from sales transactions to secured borrowing transactions as of January 1, 2010.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
In addition to the risks inherent in operations, CONSOL Energy is exposed to financial, market, political and economic risks. The following discussion provides additional detail regarding CONSOL Energy’s exposure to the risks of changing natural gas prices, interest rates and foreign exchange rates.
CONSOL Energy is exposed to market price risk in the normal course of selling natural gas production and to a lesser extent in the sale of coal. CONSOL Energy sells coal under both short-term and long-term contracts with fixed price and/or indexed price contracts that reflect market value. CONSOL Energy uses fixed-price contracts, collar-price contracts and derivative commodity instruments that qualify as cash-flow hedges under the Derivatives and Hedging Topic of the Financial Accounting Standards Board Accounting Standards Codification to minimize exposure to market price volatility in the sale of natural gas. Our risk management policy prohibits the use of derivatives for speculative purposes.
CONSOL Energy has established risk management policies and procedures to strengthen the internal control environment of the marketing of commodities produced from its asset base. All of the derivative instruments without other risk assessment procedures are held for purposes other than trading. They are used primarily to mitigate uncertainty and volatility and cover underlying exposures. CONSOL Energy’s market risk strategy incorporates fundamental risk management tools to assess market price risk and establish a framework in which management can maintain a portfolio of transactions within pre-defined risk parameters.
CONSOL Energy believes that the use of derivative instruments, along with the risk assessment procedures and internal controls, mitigates our exposure to material risk. However, the use of derivative instruments without other risk assessment procedures could materially affect CONSOL Energy results of operations depending on interest rates or market prices. Nevertheless, we believe that use of these instruments will not have a material adverse effect on our financial position or liquidity.
For a summary of accounting policies related to derivative instruments, see Note 1 of the Notes to the Consolidated Financial Statements in Item 8
Item 8. Financial Statements and Supplementary Data.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Reports of Independent Registered Public Accounting Firms
Consolidated Statements of Income for the Years Ended December 31, 2009, 2008 and
Consolidated Balance Sheets at December 31, 2009 and 2008
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2009, 2008 and 2007
Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and
Notes to Audited Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of CONSOL Energy Inc.
We have audited the accompanying consolidated balance sheets of CONSOL Energy Inc. (and Subsidiaries) as of December 31, 2009 and 2008, and the related consolidated statements of income, stockholders’ equity, and cash flows for the years then ended. Our audit also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule 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 the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of CONSOL Energy Inc. (and Subsidiaries) at December 31, 2009 and 2008, and the consolidated results of their operations and their cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As discussed in Note 1 to the consolidated financial statements, the Company has changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements. As discussed in Note 15 to the consolidated financial statements, during the year ended December 31, 2008, the Company adopted the measurement provisions related to pension and other postretirement benefit obligations.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), CONSOL Energy, Inc.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 9, 2010 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Pittsburgh, Pennsylvania
February 9, 2010
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of CONSOL Energy Inc.:
In our opinion, the consolidated statements of income, stockholders’ equity and cash flows for the year ended December 31, 2007 present fairly, in all material respects, the results of CONSOL Energy Inc. and its subsidiaries (CONSOL Energy) operations and their cash flows for the year ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule included in Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of CONSOL Energy’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, CONSOL Energy changed the manner in which it accounts for non-controlling interests effective January 1, 2009.
/s/ PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania
February 18, 2008, except with respect to our opinion on the consolidated financial statements insofar as it relates to the effects of the change in accounting for non-controlling interests discussed in Note 1 to the consolidated financial statements, as to which the date is June 26, 2009.
CONSOL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in thousands, except per share data)
The accompanying notes are an integral part of these consolidated financial statements.
CONSOL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands, except per share data)
The accompanying notes are an integral part of these consolidated financial statements.
CONSOL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(Dollars in thousands, except per share data)
The accompanying notes are an integral part of these consolidated financial statements.
CONSOL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOW
(Dollars in thousands, except per share data)
The accompanying notes are an integral part of these consolidated financial statements.
See Note 20-Supplemental Cash Flow
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Note 1-Significant Accounting Policies:
A summary of the significant accounting policies of CONSOL Energy Inc. and subsidiaries (CONSOL Energy) is presented below. These, together with the other notes that follow, are an integral part of the Consolidated Financial Statements.
Basis of Consolidation:
The Consolidated Financial Statements include the accounts of majority-owned and controlled subsidiaries. The accounts of variable interest entities (VIEs) as defined by the Consolidation Topic of the Financial Accounting Standards Board’s (FASB) Accounting Standards Codification where CONSOL Energy is the primary beneficiary, are included in the consolidated financial statements. Investments in business entities in which CONSOL Energy does not have control, but has the ability to exercise significant influence over the operating and financial policies, are accounted for under the equity method. All significant intercompany transactions and accounts have been eliminated in consolidation.
Use of Estimates:
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and various disclosures. Actual results could differ from those estimates. The most significant estimates included in the preparation of the financial statements are related to other postretirement benefits, coal workers’ pneumoconiosis, workers’ compensation, salary retirement benefits, stock-based compensation, reclamation, mine closure and gas well plugging liabilities, deferred income tax assets and liabilities, contingencies, and coal and gas reserve values.
Cash and Cash Equivalents:
Cash and cash equivalents include cash on hand and on deposit at banking institutions as well as all highly liquid short-term securities with original maturities of three months or less.
Trade Accounts Receivable:
Trade accounts receivable are recorded at the invoiced amount and do not bear interest. CONSOL Energy reserves for specific accounts receivable when it is probable that all or a part of an outstanding balance will not be collected, such as customer bankruptcies. Collectability is determined based on terms of sale, credit status of customers and various other circumstances. CONSOL Energy regularly reviews collectability and establishes or adjusts the allowance as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Reserves for uncollectible amounts were not material in the periods presented.
Inventories:
Inventories are stated at the lower of cost or market. The cost of coal inventories is determined by the first-in, first-out (FIFO) method. Coal inventory costs include labor, supplies, equipment costs, operating overhead and other related costs. The cost of merchandise for resale is determined by the last-in, first-out (LIFO) method and includes industrial maintenance, repair and operating supplies for sale to third parties. The cost of supplies inventory is determined by the average cost method and includes operating and maintenance supplies to be used in our mining operations.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Property, Plant and Equipment:
Property, plant and equipment is carried at cost. Expenditures which extend the useful lives of existing plant and equipment are capitalized. Interest costs applicable to major asset additions are capitalized during the construction period. Costs of additional mine facilities required to maintain production after a mine reaches the production stage, generally referred to as “receding face costs,” are expensed as incurred; however, the costs of additional airshafts and new portals are capitalized. Planned major maintenance costs which do not extend the useful lives of existing plant and equipment are expensed as incurred.
Coal exploration costs are expensed as incurred. Coal exploration costs include those incurred to ascertain existence, location, extent or quality of ore or minerals before beginning the development stage of the mine.
Costs of developing new underground mines and certain underground expansion projects are capitalized. Underground development costs, which are costs incurred to make the mineral physically accessible, include costs to prepare property for shafts, driving main entries for ventilation, haulage, personnel, construction of airshafts, roof protection and other facilities. Costs of developing the first pit within a permitted area of a surface mine are capitalized. A surface mine is defined as the permitted mining area which includes various adjacent pits that share common infrastructure, processing equipment and a common ore body. Surface mine development costs include construction costs for entry roads, drilling, blasting and removal of overburden in developing the first cut for mountain stripping or box cuts for surface stripping. Stripping costs incurred during the production phase of a mine are expensed as incurred.
Advance mining royalties are advance payments made to lessors under terms of mineral lease agreements that are recoupable against future production using the units-of-production method. Depletion of leased coal interests is computed using the units-of-production method over proven and probable coal reserves. Advance mining royalties and leased coal interests are evaluated periodically for impairment issues or whenever events or changes in circumstances indicate that the carrying amount may not be recoverable.
When properties are retired or otherwise disposed, the related cost and accumulated depreciation are removed from the respective accounts and any profit or loss on disposition is recognized in other income.
Gas wells are accounted for under the successful efforts method of accounting. Costs of property acquisitions, successful exploratory wells, development wells and related support equipment and facilities are capitalized. Costs of unsuccessful exploratory wells are expensed when such wells are determined to be non-productive, or if the determination cannot be made after finding sufficient quantities of reserves to continue evaluating the viability of the project. The costs of producing properties and mineral interests are amortized using the units-of-production method. Wells and related equipment and intangible drilling costs are amortized on a units-of-production method. Units-of-production amortization rates are revised when events and circumstances indicate an adjustment is necessary, but at least once a year; those revisions are accounted for prospectively as changes in accounting estimates.
Depreciation of mining plant and equipment is calculated on the straight-line method over their estimated useful lives or lease terms generally as follows:
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Costs to obtain coal lands are capitalized based on the fair value at acquisition and are amortized using the units-of-production method over all estimated proven and probable reserve tons assigned and accessible to the mine. Proven and probable coal reserves exclude non-recoverable coal reserves and anticipated processing losses. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when events and circumstances indicate a reserve change is needed, or at a minimum once a year. Amortization of coal interests begins when the coal reserve is produced. At an underground mine, a ton is considered produced once it reaches the surface area of the mine. Any material income effect from changes in estimates is disclosed in the period the change occurs.
Airshafts and capitalized mine development associated with a coal reserve are amortized on a units-of-production basis as the coal is produced so that each ton of coal is assigned a portion of the unamortized costs. We employ this method to match costs with the related revenues realized in a particular period. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when information becomes available that indicates a reserve change is needed, or at a minimum once a year. Any material income effect from changes in estimates is disclosed in the period the change occurs. Amortization of development cost begins when the development phase is complete and the production phase begins. At an underground mine, the end of the development phase and the beginning of the production phase takes place when construction of the mine for economic extraction is substantially complete. Coal extracted during the development phase is incidental to the mine’s production capacity and is not considered to shift the mine into the production phase.
Costs for purchased and internally developed software are expensed until it has been determined that the software will result in probable future economic benefits and management has committed to funding the project. Thereafter, all direct costs of materials and services incurred in developing or obtaining software, including certain payroll and benefit costs of employees associated with the project, are capitalized and amortized using the straight-line method over the estimated useful life which does not exceed 7 years.
Impairment of Long-lived Assets:
Impairment of long-lived assets is recorded when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying value. The carrying value of the assets is then reduced to its estimated fair value which is usually measured based on an estimate of future discounted cash flows. Impairment of equity investments is recorded when indicators of impairment are present and the estimated fair value of the investment is less than the assets’ carrying value. Impairment expense of $4,211 was recognized in Cost of Goods Sold and Other Operating Charges for the year ended December 31, 2009 for the impairment of certain sales contract assets. Impairment expense of $3,773 was recognized in Cost of Goods Sold and Other Operating Charges in December 2008, when it became probable that an option to purchase preferred equity in PFBC Environment Energy Technology would not be exercised.
Income Taxes:
Deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized in CONSOL Energy’s financial statements or tax returns. The provision for income taxes represents income taxes paid or payable for the current year and the change in deferred taxes, excluding the effects of acquisitions during the year. Deferred taxes result from differences between the financial and tax bases of CONSOL Energy’s assets and liabilities and are adjusted for changes in tax rates and tax laws when changes are enacted. Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that a deferred tax benefit will not be realized.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
As required by the Income Tax Topic of the FASB Accounting Standards Codification, CONSOL Energy evaluates all tax positions taken on the state and federal tax filings to determine if the position is more likely than not to be sustained upon examination. For positions that meet the more likely than not to be sustained criteria, an evaluation to determine the largest amount of benefit, determined on a cumulative probability basis that is more likely than not to be realized upon ultimate settlement, is determined. A previously recognized tax position is derecognized when it is subsequently determined that a tax position no longer meets the more likely than not threshold to be sustained. The evaluation of the sustainability of a tax position and the probable amount that is more likely than not is based on judgment, historical experience and on various other assumptions that we believe are reasonable under the circumstances. The results of these estimates, that are not readily apparent from other sources, form the basis for recognizing an uncertain tax position liability. Actual results could differ from those estimates upon subsequent resolution of identified matters.
Postretirement Benefits Other Than Pensions:
Postretirement benefits other than pensions, except for those established pursuant to the Coal Industry Retiree Health Benefit Act of 1992 (the Health Benefit Act), are accounted for in accordance with the Retirement Benefits Compensation and Non-retirement Postemployment Benefits Compensation Topics of the FASB Accounting Standards Codification which requires employers to accrue the cost of such retirement benefits for the employees’ active service periods. Such liabilities are determined on an actuarial basis and CONSOL Energy is primarily self-insured for these benefits. Postretirement benefit obligations established by the Health Benefit Act are treated as a multi-employer plan which requires expense to be recorded for the associated obligations as payments are made. This treatment is in accordance with the Retirement Benefits Compensation (Extractive Activities-Mining) Topic of the FASB Accounting Standards Codification.
Pneumoconiosis Benefits and Workers’ Compensation:
CONSOL Energy is required by federal and state statutes to provide benefits to certain current and former totally disabled employees or their dependents for awards related to coal workers’ pneumoconiosis. CONSOL Energy is also required by various state statutes to provide workers’ compensation benefits for employees who sustain employment related physical injuries or some types of occupational disease. Workers’ compensation benefits include compensation for their disability, medical costs, and on some occasions, the cost of rehabilitation. CONSOL Energy is primarily self-insured for these benefits. Provisions for estimated benefits are determined on an actuarial basis.
Mine Closing, Reclamation and Gas Well Closing:
CONSOL Energy accrues for reclamation costs, mine closing costs, perpetual water care costs and dismantling and removing costs of gas related facilities using the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification. This statement requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Depreciation of the capitalized asset retirement cost is generally determined on a units-of-production basis. Accretion of the asset retirement obligation is recognized over time and generally will escalate over the life of the producing asset, typically as production declines. Accretion is included in the Cost of Goods Sold and Other Operating Charges line on the Consolidated Statements of Income. Asset retirement obligations primarily relate to the closure of mines and gas wells, and includes treatment of water and the reclamation of land upon exhaustion of coal and gas reserves.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Accrued mine closing costs, perpetual care costs, reclamation and costs of dismantling and removing gas related facilities are regularly reviewed by management and are revised for changes in future estimated costs and regulatory requirements.
Retirement Plans:
CONSOL Energy has non-contributory defined benefit retirement plans covering substantially all employees not covered by multi-employer retirement plans. Effective January 1, 2007, employees hired by CNX Gas, an 83.3% owned subsidiary, will not be eligible to participate in the non-contributory defined benefit retirement plan. In lieu of participation in this plan, these employees began receiving an additional 3% company contribution into their defined contribution plan.
Revenue Recognition:
Revenues are recognized when title passes to the customers. For domestic coal sales, this generally occurs when coal is loaded at mine or offsite storage locations. For export coal sales, this generally occurs when coal is loaded onto marine vessels at terminal locations. For gas sales, this occurs at the contractual point of delivery. For industrial supplies and equipment sales, this generally occurs when the products are delivered. For terminal, river and dock, land, research and development, and coal waste disposal services, revenue is recognized generally as the service is provided to the customer.
CNX Gas has operational gas-balancing agreements with various interstate pipelines. These imbalance agreements are managed internally using the sales method of accounting. The sales method recognizes revenue when the gas is taken by the purchaser.
CNX Gas sells gas to accommodate the delivery points of its customers. In general this gas is purchased at market price and re-sold on the same day at market price less a small transaction fee. These matching buy/sell transactions include a legal right of offset of obligations and have been simultaneously entered into with the counterparty which qualify for netting under the Nonmonetary Transactions Topic of the FASB Accounting Standards Codification and are therefore reflected net on the income statement in Cost of Goods Sold and Other Operating Charges.
CNX Gas also provides gathering services to third parties by purchasing gas produced by the third party, at market prices less a fee. The gas purchased from third party producers is then resold by CNX Gas to end users or gas marketers at current market prices. These revenues and expenses are recorded gross as purchased gas revenue and purchased gas costs in the Consolidated Statements of Income. Purchased gas revenue is recognized when title passes to the customer. Purchased gas costs are recognized when title passes to CNX Gas from the third party producer.
Royalty Interest Gas Sales represent the revenues for the portion of production associated with royalty interest owners.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Freight Revenue and Expenses:
Shipping and handling costs invoiced to coal customers and paid to third-party carriers are recorded as Freight Revenue and Freight Expense, respectively.
Royalty Recognition:
Royalty expenses for coal rights are included in Cost of Goods Sold and Other Operating Charges when the related revenue for the coal sale is recognized. Royalty expenses for gas rights are included in Gas Royalty Interest Costs when the related revenue for the gas sale is recognized. These royalty expenses are paid in cash in accordance with the terms of each agreement. Revenues for coal and gas sold related to production under royalty contracts, versus owned by CONSOL Energy, are recorded on a gross basis. The recognized revenues for these transactions are not net of related royalty fees.
Contingencies:
CONSOL Energy, or our subsidiaries, from time to time is subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations including environmental remediation, employment and contract disputes, and other claims and actions, arising out of the normal course of business. Liabilities are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Estimates are developed through consultation with legal counsel involved in the defense and are based upon an analysis of potential results, assuming a combination of litigation and settlement strategies. Environmental liabilities are not discounted or reduced by possible recoveries from third parties. Legal fees associated with defending these various lawsuits and claims are expensed when incurred.
Treasury Stock:
On September 12, 2008, CONSOL Energy’s Board of Directors announced a share repurchase program of up to $500,000 of the company’s common stock during a twenty-four month period beginning September 9, 2008, and ending September 8, 2010. Shares of common stock repurchased by us are recorded at cost as treasury stock and result in a reduction of stockholders’ equity in our Consolidated Balance Sheets. From time to time, treasury shares may be reissued as part of our stock-based compensation programs. When shares are reissued, we use the weighted average cost method for determining cost. The difference between the cost of the shares and the issuance price is added to or deducted from Capital in Excess of Par Value.
On December 21, 2005, CONSOL Energy’s Board of Directors announced a share repurchase program of up to $300,000 of the company’s common stock during a twenty-four month period beginning January 1, 2006 and ending December 31, 2007.
For the years ended December 31, 2008 and 2007, we had cash expenditures under our repurchase program of $97,794 and $80,157, respectively, funded primarily by cash generated from operations. The total common shares repurchased for the years ended December 31, 2008 and 2007 were 2,741,300 and 2,087,800 at an average cost of $35.59 and $38.14 per share, respectively. There were no cash expenditures under our repurchase program for the year ended December 31, 2009.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Stock-Based Compensation:
Stock-based compensation expense for all stock-based compensation awards is based on the grant date fair value estimated in accordance with the provisions of Stock Compensation Topic of the FASB Accounting Standards Codification. CONSOL Energy recognizes these compensation costs on a straight-line basis over the requisite service period of the award, which is generally the option vesting term. See Note 18 to the Audited Consolidated Financial Statements for a further discussion on stock-based compensation.
Earnings per Share:
Basic earnings per share are computed by dividing net earnings by the weighted average shares outstanding during the reporting period. Dilutive earnings per share are computed similar to basic earnings per share except that the weighted average shares outstanding are increased to include additional shares from the assumed exercise of stock options, and the assumed vesting of restricted and performance stock units if dilutive. The number of additional shares is calculated by assuming that outstanding stock options were exercised, and outstanding restricted and performance stock units were released, and that the proceeds from such activities were used to acquire shares of common stock at the average market price during the reporting period. In accordance with the provisions of the Stock Compensation Topic of the FASB Accounting Standards Codification, CONSOL Energy includes the impact of the proforma deferred tax assets in determining potential windfalls and shortfalls for purposes of calculating assumed proceeds under the treasury stock method. The table below sets forth the outstanding options, unvested restricted stock units, and unvested performance stock units that have been excluded from the computation of diluted earnings per share because their effect would be anti-dilutive.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Shares of common stock outstanding were as follows:
(1) See Note 18-Stock-based Compensation for additional information.
Accounting for Derivative Instruments:
CONSOL Energy accounts for derivative instruments in accordance with the Derivatives and Hedging Topic of the FASB Accounting Standards Codification. This requires CONSOL Energy to measure every derivative instrument (including certain derivative instruments embedded in other contracts) at fair value and record them in the balance sheet as either an asset or liability. Changes in fair value of derivatives are recorded currently in earnings unless special hedge accounting criteria are met. For derivatives designated as cash flow hedges, the effective portions of changes in fair value of the derivative are reported, net of applicable taxes, in other comprehensive income. The ineffective portions of hedges are recognized in earnings in the current period.
CONSOL Energy formally assesses, both at inception of the hedge and on an ongoing basis, whether each derivative is highly effective in offsetting changes in fair values or cash flows of the hedged item. If it is determined that a derivative is not highly effective as a hedge, or if a derivative ceases to be a highly effective hedge, CONSOL Energy will discontinue hedge accounting prospectively.
Accounting for Business Combinations:
The company accounts for its business acquisitions under the purchase method of accounting consistent with the requirements of the Business Combination Topic of the FASB Accounting Standards Codification. The total cost of acquisitions is allocated to the underlying identifiable net assets, based on their respective estimated fair values. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, and the utilization of independent valuation experts, and often involves the use of significant estimates and assumptions with respect to future cash inflows and outflows, discount rates and asset lives, among other items.
Accounting for Carbon Emissions Offsets:
In 2008, CNX Gas, an 83.3% subsidiary, completed the independent verification and registration processes necessary to sell carbon emission offsets on the Chicago Climate Exchange. CNX Gas has verified approximately 8.4 million metric tons of offsets, CONSOL Energy has also verified approximately 8.3 million metric tons of offsets which may sell on the over-the-counter market. These offsets are recorded at their historical cost, which is zero. Sales of these emission offsets will be reflected in income as they occur. To date, no offsets have been sold.
Recently Adopted Accounting Guidance:
In December 2009, CONSOL adopted authoritative guidance issued by the FASB on extractive activities for oil and gas reserve estimation and disclosures. The objective of the new guidance is to align the oil and gas reserve estimation and disclosure requirements with the requirements of the Securities and Exchange
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Commission. The new guidance, among other purposes, is primarily intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves by expanding the definition of proved oil and gas producing activities, disclosing geographical areas that represent a certain percentage of proved reserves, updating the reserve estimation requirements for changes in practice and technology that have occurred over the past several decades and requiring that an entity continue to disclose separately the amounts and quantities for consolidated and equity method investments. CONSOL has applied this guidance to its Financial Statements for the year ended December 31, 2009.
Recent Accounting Guidance Not Yet Adopted:
In June 2009, the FASB issued authoritative guidance on the consolidation of variable interest entities, which is effective for CONSOL beginning July 1, 2010. The new guidance requires revised evaluations of whether entities represent variable interest entities, ongoing assessments of control over such entities, and additional disclosures for variable interests. We believe adoption of this new guidance will not have material impact on CONSOL’s financial statements.
In June 2009, the FASB issued accounting guidance regarding the accounting for transfers of financial assets that is designed to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial statements about a transfer of financial assets; the effects of a transfer on its financial position, financial performance, and cash flows; and a transferor’s continuing involvement, if any, in transferred financial assets. The guidance enhances the information provided to financial statement users to provide greater transparency about transfers of financial assets and a transferor’s continuing involvement, if any, with transferred financial assets. The guidance requires enhanced disclosures about the risks that a transferor continues to be exposed to because of its continuing involvement in transferred financial assets. This guidance is effective for an entity’s first annual reporting period after November 15, 2009 and is not eligible for early adoption. Management believes that this guidance will result in the securitization facility transactions being reclassified from sales transactions to secured borrowing transactions as of January 1, 2010.
Reclassifications:
Certain reclassifications of prior period data have been made to conform to the year ended December 31, 2009 as required by the Noncontrolling Interest Topic of the FASB Accounting Standards Codification.
Subsequent Events:
We have evaluated all subsequent events through February 9, 2010, the date the financial statements were issued. No material recognized or non-recognizable subsequent events were identified.
Note 2-Acquisitions and Dispositions:
In August 2009, CONSOL Energy completed the lease assignment of CNX Gas’, an 83.3% owned subsidiary, previous headquarters. Total expense related to this transaction for the year ended December 31, 2009 was $1,500, which was recognized in the Cost of Goods Sold and Other Operating Charges.
In August 2009, CONSOL Energy completed a sale/lease-back of longwall shields for Bailey Mine. Cash proceeds from the sale were $16,011, which was the same as our basis in the equipment. Accordingly, no gain or loss was recognized on the transaction. The lease has been accounted for as an operating lease. The lease term is five years.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
In July 2009, CNX Gas leased approximately 20,000 acres having Marcellus Shale potential from NiSource Energy Ventures, LLC, a subsidiary of the Columbia Energy Group, for a cash payment of $8,275 which is included in capital expenditures in Cash Used in Investing Activities on the Consolidated Statement of Cash Flows. The purchase price for the transaction was principally allocated to gas properties and related development.
In June 2009, CONSOL Energy recognized the fair value of the remaining lease payments in the amount of $10,499 in accordance with the Exit or Disposal Cost Obligations topic of the Financial Accounting Standards Board Accounting Standards Codification related to the Company’s previous headquarters. This liability has been recorded in Other Liabilities on the consolidated balance sheet at December 31, 2009. Total expense related to this transaction was $12,500, which was recognized in the Cost of Goods Sold and Other Operating Charges. This amount includes lease payments of $10,974 as well as the removal of a related asset of $1,526. Additionally, $5,832 was recognized in the Other Income for the acceleration of a deferred gain associated with the initial sale-leaseback of the premises that occurred in 2005.
In February 2009, CONSOL Energy completed a sale/lease-back of longwall shields for Bailey Mine. Cash proceeds for the sale were $42,282, which was the same as our basis in the equipment. Accordingly, no gain or loss was recognized on the transaction. The lease has been accounted for as an operating lease. The lease term is five years.
In December 2008, CONSOL Energy completed the acquisition of the outstanding 51% interest in Southern West Virginia Energy, LLC (“SWVE”) for a cash payment of $11,521. This amount is included in capital expenditures in Cash Used in Investing Activities on the Consolidated Statement of Cash Flows. The purchase price was principally allocated to property, plant and equipment. SWVE wholly-owns Southern West Virginia Resources, LLC and Minway Contracting, LLC, and had previously been a 49% subsidiary of CONSOL Energy. Prior to the acquisition of the outstanding interest, SWVE had been fully consolidated in accordance with the Consolidation Topic of the Financial Accounting Standards Board Accounting Standards Codification by CONSOL Energy. The proforma results for this acquisition are not material to CONSOL Energy’s financial results.
In November 2008, CONSOL Energy completed the acquisition of North Penn Pipe & Supply, Inc. for a cash payment, net of cash acquired, of $22,550. This amount is included in capital expenditures in Cash Used in Investing Activities on the Consolidated Statements of Cash Flows. North Penn Pipe & Supply, Inc. is a distributor of oil and gas field equipment, primarily tubular goods, to the northern Appalachian Basin, a region stretching from the state of New York to southwestern Pennsylvania and northern West Virginia. The fair value of merchandise for resale acquired in this acquisition is $10,623 and is included in inventory on the Consolidated Balance Sheets as of the acquisition date. The pro forma results for this acquisition are not significant to CONSOL Energy’s financial results.
In October 2008 CONSOL Energy Inc.’s Board of Directors has authorized a purchase program for shares of CNX Gas Corporation common stock for an aggregate purchase price of up to $150 million. The authorization, which is not intended to take CNX Gas private, was effective as of October 21, 2008 for a twenty-four month period. During the year ended December 31, 2008, CONSOL Energy completed the purchase of $67,259 of CNX Gas stock on the open market at an average price of $26.53 per share. The purchase of these 2,531,400 shares changed CONSOL Energy’s ownership percentage in CNX Gas from 81.7% to 83.3% at December 31, 2008. During the year ended December 31, 2007, CONSOL Energy purchased $10,000 of CNX Gas stock on the open market at an average price of $26.87 per share. The purchase of these 372,000 shares changed CONSOL Energy’s ownership percentage in CNX Gas from 81.5% to 81.7% at December 31, 2007.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
In July 2008, CNX Gas completed the acquisition of several leases and gas wells from KIS Oil & Gas Inc. for a cash payment of $19,324. The purchase price was principally allocated to property, plant and equipment. The sales agreement called for the transfer of 30 oil and gas wells and approximately 5,600 leased acres. This acquisition enhanced our acreage position in Northern Appalachia. The pro forma results for this acquisition were not significant to CONSOL Energy’s financial results.
In June 2008, CNX Gas completed the acquisition of the remaining 50% interest in Knox Energy, LLC and Coalfield Pipeline Company not already owned by CNX Gas for a cash payment of $36,000 which was principally allocated to gas properties and related development and gas gathering equipment. Knox Energy, LLC had been proportionately consolidated into CONSOL Energy’s financial statements during 2008. During 2007 the equity method was used to account for these entities. Knox Energy, LLC is a natural gas production company and Coalfield Pipeline Company is a gathering and transportation company with operations in Tennessee. The pro forma results for this acquisition were not significant to CONSOL Energy’s financial results.
In February 2008, CONSOL Energy completed the sale of the Mill Creek Mining Complex located in Kentucky. The sales agreement called for the transfer of all of the assets comprising the complex. Cash proceeds from the sale were $14,649, with our basis in the assets being $9,934. Accordingly, a gain of $4,715 was recorded on the transaction.
In December 2007, CONSOL Energy completed a sale/lease-back of 35 river barges. Cash proceeds from the sale were $16,895, with our basis in the equipment being $16,951. Accordingly, a loss of $56 was recorded on the transaction. The lease has been accounted for as an operating lease. The lease term is fourteen years.
In October 2007, CONSOL Energy acquired 100% of the outstanding shares in an oil and gas company for a cash payment of $12,385 which was principally allocated to gas properties and related development and gas gathering equipment. The acquired company is in the business of owning, operating and producing oil and gas wells and related pipelines. The acquired assets consisted of gas wells, equipment and connecting pipelines utilized in well operations. The acquisition was accounted for according to the Business Combination Topic of the Financial Accounting Standards Board Accounting Standards Codification. The pro forma results for this acquisition were not significant to CONSOL Energy’s financial results.
In July, 2007, CONSOL Energy acquired 100% of the voting interest of AMVEST Corporation and certain subsidiaries and affiliates (AMVEST) for a cash payment, net of cash acquired, of $296,724 in a transaction accounted for according to the Business Combination Topic of the Financial Accounting Standards Board Accounting Standards Codification. The coal reserves acquired consisted of approximately 160 million tons of high quality, low sulfur steam and high-volatile metallurgical coal. Also included in the acquisition were four coal preparation plants, several fleets of modern mining equipment and a common short-line railroad that connects the coal preparation plants to the CSX and Norfolk and Southern rail interchanges. The results of operations of the acquired entities are included in CONSOL Energy’s Consolidated Statements of Income as of August 1, 2007.
The AMVEST acquisition, when combined with CONSOL Energy’s adjacent coal reserves, creates a large contiguous block of coal reserves in the Central Appalachian region. Also, included in the acquisition was a highly-skilled workforce proficient in Central Appalachian surface mining. This workforce combined with CONSOL Energy’s underground mining expertise will allow us to build and transfer knowledge among operations to focus the best skill sets to development requirements of the various parts of this reserve block.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The unaudited pro forma results, assuming the acquisition had occurred at January 1, 2007 are estimated to be:
The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of 2007, nor are they necessarily indicative of future consolidated results.
In July 2007, CONSOL Energy completed the acquisition of Piping & Equipment, Inc. for a cash payment, net of cash acquired, of $16,914. This amount is included in capital expenditures in Cash Used in Investing Activities on the Consolidated Statements of Cash Flows. Piping & Equipment, Inc. is a pipe, valve and fittings supplier with eight locations in Florida, Alabama, Louisiana and Texas. The fair value of merchandise for resale acquired in this acquisition is $8,481 and is included in inventory on the Consolidated Balance Sheets. The pro forma results for this acquisition are not significant to CONSOL Energy’s financial results.
In June 2007, CONSOL Energy exchanged certain coal assets in Northern Appalachia with Peabody Energy for coalbed methane and gas rights. This transaction was accounted for as a non-monetary exchange under the Fair Value Measurements and Disclosures Topic of the Financial Accounting Standards Board Accounting Standards Codification resulting in a pre-tax gain of $50,060. Also in June 2007, CONSOL Energy, through a subsidiary, acquired certain coalbed methane and gas rights from Peabody Energy for a cash payment of $15,000 plus approximately $1,650 of various other acquisition costs.
In June 2007, CONSOL Energy sold the rights to certain western Kentucky coal in the Illinois Basin to Alliance Resource Partners, L.P. for $53,309. This transaction resulted in a pre-tax gain of $49,868.
Note 3-Other Income:
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Note 4-Interest Expense:
Note 5-Taxes Other Than Income:
Note 6-Income Taxes:
Income taxes (benefits) provided on earnings consisted of:
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The components of the net deferred tax assets are as follows:
** Valuation allowances of ($3,051) and ($58,572) have been allocated between current and long-term deferred tax assets respectively for 2009. Valuation allowances of ($2,663) and ($58,235) have been allocated between current and long-term deferred tax assets respectively for 2008.
A valuation allowance is required when it is more likely than not that all or a portion of a deferred tax asset will not be realized. All available evidence, both positive and negative, must be considered in determining the need for a valuation allowance. For the years ended December 31, 2009 and 2008, positive evidence considered included future income projections based on existing fixed price contracts and forecasted expenses, reversals of financial to tax temporary differences and the implementation of and/or ability to employ various tax planning strategies. Negative evidence included financial and tax losses generated in prior periods and the inability to achieve forecasted results for those periods.
In 2007, CONSOL Energy implemented a prudent and feasible tax strategy that ensured the realization of Pennsylvania loss carry forward tax benefits. For 2009 and 2008, CONSOL Energy continues to report a deferred tax asset of $16,081 and $22,656 on an after federal tax adjusted basis relating to the remainder of its state operating loss carry forwards after valuation allowances, respectively. A review of the positive and negative evidence regarding these tax benefits, primarily the history of financial and tax losses on a separate company basis, concluded that the valuation allowances were warranted. A valuation allowance of $24,571 and $26,184 on an after federal tax adjusted basis has also been recorded for 2009 and 2008 respectively, against the deferred state tax asset attributable to future deductible temporary differences for certain CONSOL Energy subsidiaries with histories of financial and tax losses. The net operating loss carryforwards expire at various times between 2010 and 2027. Management will continue to assess the potential for realizing deferred tax assets based upon
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
income forecast data and the feasibility of future tax planning strategies and may record adjustments to valuation allowances against deferred tax assets in future periods as appropriate, that could materially impact net income. Included in the valuation allowance against the deferred state tax assets attributable to future deductible temporary differences for 2009 and 2008 are $7,952 and $8,496, respectively, of future tax benefits relating to other postretirement, pension and long-term disability benefits which are subject to a full valuation allowance. The decrease in the valuation allowances recognized related to other postretirement, pension and long-term disability benefits were recognized through Other Comprehensive Income in the applicable period.
We estimate that CONSOL Energy will utilize federal alternative minimum tax credits of $60,032 for the year ended December 31, 2009, thereby reducing the deferred tax asset associated with the prior years’ minimum tax credits. During 2009, the federal alternative minimum tax credits were increased $3,631 as a result of the 2008 accrual to 2008 return adjustments. As a result of the conclusion of the Internal Revenue Service (IRS) examination of the 2004 and 2005 tax returns, CONSOL Energy was able to utilize an additional $9,846 of alternative minimum tax credits.
The following is a reconciliation stated as a percentage of pretax income, of the United States statutory federal income tax rate to CONSOL Energy’s effective tax rate:
A reconciliation of the beginning and ending gross amounts of unrecognized tax benefits is as follows:
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
If these unrecognized tax benefits were recognized, $15,502 and $14,657 respectively would affect CONSOL Energy’s effective income tax rate.
CONSOL Energy and its subsidiaries file income tax returns in the U.S. federal, various states and Canadian jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for the years before 2005. During the year ended December 31, 2009, CONSOL Energy was advised by the Canadian Revenue Agency that its appeal of tax deficiencies paid as a result of the Agency’s audit of the Company’s Canadian tax returns filed for years 1997 through 2002 had been successfully resolved. The Company recorded a tax refund receivable of $4,560 as a result of the audit settlement.
During the year ended December 31, 2009, CONSOL Energy paid federal and state income tax deficiencies of $12,798 and $608, respectively. The federal and state deficiencies paid, as a result of the 2004 and 2005 tax returns, had an insignificant impact on net income due to the tax deficiencies being the result of changes in the timing of certain tax deductions.
The IRS is commencing its audit of CONSOL Energy’s income tax returns filed for 2006 and 2007. The Company expects to conclude this examination and remit payment of any resulting tax deficiencies to federal and state taxing authorities before December 31, 2010. Since the IRS examination is in its initial stages, any resulting tax deficiency or overpayment cannot be estimated at this time. During the next year the statute of limitations for assessing additional income tax deficiencies will expire for certain tax years in several state tax jurisdictions. The expiration of the statute of limitations for these years will have an insignificant impact on CONSOL Energy’s total uncertain income tax positions and net income for the twelve-month period.
CONSOL Energy recognizes interest accrued related to unrecognized tax benefits in its interest expense. At December 31, 2009 and 2008, the Company had an accrued liability of $8,338 and $10,518, respectively, for interest related to uncertain tax positions. The accrued interest liabilities include $2,409, $2,012 and $3,426 that were recorded in the Company’s Consolidated Statements of Income for the years ended December 31, 2009 and 2008, respectively. During the year ended December 31, 2009, CONSOL Energy paid interest of $4,590 related to income tax deficiencies to the IRS as a result of its examinations of the Company’s tax returns filed for the years 2002 through 2005.
CONSOL Energy recognizes penalties accrued related to unrecognized tax benefits in its income tax expense. As of December 31, 2009 and 2008, there were no accrued penalties recognized.
Note 7-Mine Closing, Reclamation & Gas Well Closing:
CONSOL Energy accrues for reclamation, mine closing costs, perpetual water care costs and dismantling and removing costs of gas related facilities using the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the FASB Accounting Standards Codification. CONSOL Energy recognizes capitalized asset retirement costs by increasing the carrying amount of related long-lived assets, net of the associated accumulated depreciation. The obligation for asset retirements is included in Mine Closing, Reclamation, Gas Well Closing and Other Accrued Liabilities on the Consolidated Balance Sheets.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The reconciliation of changes in the asset retirement obligations at December 31, 2009 and 2008 is as follows:
For the year ended December 31, 2009, Other includes ($283) of various other items, none of which are individually significant. For the year ended December 31, 2008, Other includes ($19,618) for asset dispositions and ($177) of various other items, none of which are individually significant.
Note 8-Inventories:
Inventory components consist of the following:
Merchandise for resale is valued using the last-in, first-out (LIFO) cost method. The excess of replacement cost of merchandise for resale inventories over carrying LIFO value was $13,696 and $14,716 at December 31, 2009 and 2008, respectively.
Note 9-Accounts Receivable Securitization:
CONSOL Energy and certain of our U.S subsidiaries are party to a trade accounts receivable facility with financial institutions for the sale on a continuous basis of eligible trade accounts receivable. This facility allows CONSOL Energy to receive up to $165,000 on a revolving basis. The facility also allows for the issuance of letters of credit against the $165,000 capacity. At December 31, 2009, there were no letters of credit outstanding against the facility.
CONSOL Energy formed CNX Funding Corporation, a wholly owned, special purpose, bankruptcy-remote subsidiary for the sole purpose of buying and selling eligible trade receivables generated by certain subsidiaries of CONSOL Energy. Under the receivables facility, CONSOL Energy and certain subsidiaries, irrevocable and without recourse, sell all of their eligible trade accounts receivable to financial institutions and their affiliates, while maintaining a subordinated interest in a portion of the pool of trade receivables. This retained interest, which is included in Accounts and Notes Receivable Trade in the Consolidated Balance Sheets, is recorded at fair value. Due to the short average collection cycle for the receivables that are part of this program, the fair value
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
of our retained interest approximates the total amount of the designated pool of accounts receivable reduced by the amount of accounts receivables sold to the third-party financial institutions under the program. CONSOL Energy will continue to service the trade receivables for the financial institutions for a fee based upon market rates for similar services.
The cost of funds under this facility is based upon commercial paper rates, plus a charge for administrative services paid to the financial institutions. Costs associated with the receivables facility totaled $2,990 and $5,814 for the year ended December 31, 2009 and 2008, respectively. These costs have been recorded as financing fees, which are included in Cost of Goods Sold and Other Operating Charges in the Consolidated Statements of Income. No servicing asset or liability has been recorded. The receivables facility expires in April 2012 with the underlying liquidity agreement renewing annually each April.
At December 31, 2009 and 2008, eligible accounts receivable totaled approximately $151,000 and $165,000, respectively. The subordinated retained interest approximated $101,000 at December 31, 2009. There was no subordinated retained interest at December 31, 2008. Accounts receivable totaling $50,000 and $165,000 were removed from the Consolidated Balance Sheets at December 31, 2009 and 2008, respectively. In accordance with the facility agreement, the company is able to receive proceeds based upon total eligible accounts receivable at the previous month end. CONSOL Energy’s $115,000 decrease and $39,600 increase in the accounts receivable securitization program for the years ended December 31, 2009 and 2008, respectively, is reflected in cash flows from operating activities in the Consolidated Statements of Cash Flows.
Note 10-Property, Plant and Equipment
Coal reserves are controlled either through fee ownership or by lease. The duration of the leases vary greatly; however, the lease terms generally are extended automatically to the exhaustion of economically recoverable reserves, as long as active mining continues. Coal interests held by lease provide the same rights as fee ownership for mineral extraction, and are legally considered real property interests. We also make advance payments (advanced mining royalties) to lessors under certain lease agreements that are recoupable against future production, and we make payments that are generally based upon a specified rate per ton or a percentage of gross realization from the sale of the coal. We evaluate our properties periodically for impairment issues or whenever events or circumstances indicate that the carrying amount may not be recoverable.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Coal reserves are amortized using the units-of-production method over all estimated proven and probable reserve tons assigned or accessible to the mine. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when events and circumstances indicate a reserve change is needed, or at a minimum once a year. Amortization of coal interests begins when the coal reserve is placed into production. At an underground mine, a ton is considered produced once it reaches the surface area of the mine. Any material income effect from changes in estimates is disclosed in the period the change occurs.
Amortization of capitalized mine development costs associated with a coal reserve is computed on a units-of-production basis as the coal is produced so that each ton of coal is assigned a portion of the unamortized costs. We employ this method to match costs with the related revenues realized in a particular period. Rates are updated when revisions to coal reserve estimates are made. Coal reserve estimates are reviewed when information becomes available that indicates a reserve change is needed, or at a minimum once a year. Any material income effect from changes in estimates is disclosed in the period the change occurs. Amortization of development costs begins when the development phase is complete and the production phase begins. At an underground mine, the end of the development phase and the beginning of the production phase takes place when construction of the mine for economic extraction is substantially complete. Coal extracted during the development phase is incidental to the mine’s production capacity and is not considered to shift the mine into the production phase.
Amortization of wells and related equipment and intangible drilling costs are amortized on a units-of-production method. Units-of-production amortization rates are revised whenever there is an indication of the need for a revision, but at least once a year, and accounted for prospectively.
Gas wells are accounted for under the successful efforts method of accounting. Costs of property acquisitions, successful exploratory wells, development wells and related support equipment and facilities are capitalized. Costs of unsuccessful exploratory wells are expensed when such wells are determined to be non-productive, or if the determination cannot be made after finding sufficient quantities of reserves to continue evaluating the viability of the project. The costs of producing properties and mineral interests are amortized using the units-of-production method. Wells and related equipment and intangible drilling costs are amortized on a units-of-production method. Units-of-production amortization rates are revised when events and circumstances indicate an adjustment is necessary, but at least once a year; those revisions are accounted for prospectively as changes in accounting estimates.
The following assets are amortized using the units-of-production method. Amounts reflect properties where mining or drilling operations have not yet commenced and therefore are not yet being amortized for the years ended December 31, 2009 and 2008, respectively.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
As of December 31, 2009 and 2008, plant and equipment includes gross assets under capital lease of $81,770 and $112,890, respectively. As of December 31, 2008, the Northern Appalachian coal segment maintained a $37,018 capital lease for longwall shields at Enlow Fork, which was included in Coal and other plant and equipment. In addition, for the years ended December 31, 2009 and 2008, the Gas segment maintains a capital lease for the Jewell Ridge Pipeline of $66,919, which is included in Gas gathering equipment. For the years ended December 31, 2009 and 2008, the Gas segment also maintains a capital lease for vehicles of $2,788 and $3,071, respectively, which are included in Gas properties and related development. For the years ended December 31, 2009 and 2008, the All Other segment maintains a capital lease for vehicles of $12,063 and $5,882, respectively, which are included in Coal and other plant and equipment. Accumulated amortization for capital leases was $21,893 and $31,929 at December 31, 2009 and 2008, respectively. Amortization expense for capital leases is included in depreciation expense. See Note 14-Leases for additional capital lease details.
Note 11-Short-Term Notes Payable:
CONSOL Energy has a five-year $1,000,000 senior secured credit facility, which extends through June 2012. The facility is secured by substantially all of the assets of CONSOL Energy and certain of its subsidiaries and collateral is shared equally and ratably with the holders of CONSOL Energy Inc. 7.875% bonds maturing in 2012. The Agreement does provide for the release of collateral at the request of CONSOL Energy upon achievement of certain credit ratings. Fees and interest rate spreads are based on a ratio of financial covenant debt to twelve-month trailing earnings before interest, taxes, depreciation, depletion and amortization (EBITDA), measured quarterly. The facility includes a minimum interest coverage ratio covenant of no less than 4.50 to 1.00, measured quarterly. The interest coverage ratio was 24.78 to 1.00 at December 31, 2009. The facility also includes a maximum leverage ratio covenant of not more than 3.25 to 1.00, measured quarterly. The leverage ratio was 0.87 to 1.00 at December 31, 2009. Affirmative and negative covenants in the facility limit our ability to dispose of assets, make investments, purchase or redeem CONSOL Energy common stock, pay dividends and merge with another corporation. At December 31, 2009, the $1,000,000 facility had $415,000 of borrowings outstanding and $268,360 of letters of credit outstanding, leaving $316,640 of capacity available for borrowings and the issuance of letters of credit. The facility bore a weighted average interest rate of 0.86% and 1.71% as of December 31, 2009 and 2008, respectively.
CNX Gas has a five-year $200,000 unsecured credit agreement which extends through October 2010. The agreement contains a negative pledge provision, whereas CNX Gas assets cannot be used to secure other obligations. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Covenants in the facility limit CNX Gas’ ability to dispose of assets, make investments, purchase or redeem CNX Gas stock, pay dividends and merge with another corporation. The facility includes a maximum leverage ratio covenant of not more than 3.00 to 1.00, measured quarterly. The leverage ratio was 0.38 to 1.00 at December 31, 2009. The facility also includes a minimum interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. This ratio was 68.17 to 1.00 at December 31, 2009. At December 31, 2009, the CNX Gas credit agreement had $57,850 of borrowings outstanding and $14,913 of letters of credit outstanding, leaving $127,237 of capacity available for borrowings and the issuance of letters of credit. The facility bore a weighted average interest rate of 1.69% and 2.01% as of December 31, 2009 and 2008, respectively.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Note 12-Other Accrued Liabilities:
Note 13-Long-Term Debt:
Advance royalty commitments and the other long-term variable rate notes had a weighted average interest rate of approximately 7.36% at December 31, 2009 and 10.65% at December 31, 2008. The bonds and notes are carried net of debt discount, which is being amortized over the life of the issue.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Annual undiscounted maturities on long-term debt during the next five years are as follows:
Note 14-Leases:
CONSOL Energy uses various leased facilities and equipment in our operations. Future minimum lease payments under capital and operating leases, together with the present value of the net minimum capital lease payments, at December 31, 2009, are as follows:
Rental expense under operating leases was $77,960, $63,170 and $47,765 for the years ended December 31, 2009, 2008 and 2007, respectively.
Note 15-Pension and Other Postretirement Benefit Plans:
CONSOL Energy has non-contributory defined benefit retirement plans covering substantially all employees not covered by multi-employer plans. The benefits for these plans are based primarily on years of service and employee’s pay near retirement.
The CONSOL Energy salaried plan allows for lump-sum distributions of benefits earned up until December 31, 2005 at the employees’ election. As of January 1, 2006, lump sum benefits have been frozen and prospectively the lump sum option has been eliminated. According to the Defined Benefit Plans Topic of the FASB Accounting Standards Codification, if the lump sum distributions made for the plan year, which for CONSOL Energy is January 1 to December 31, exceed the total of the service cost and interest cost for the plan
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
year, settlement accounting is required. Lump sum payments did not exceed the threshold during 2009 or 2008. Lump sum payments exceeded this threshold during 2007. Accordingly, CONSOL Energy recognized expense of $2,734 for the year ended December 31, 2007 in the results of operations. The adjustment equaled the unrecognized actuarial loss resulting from each individual who received a lump sum in that year. CONSOL Energy regularly monitors this situation.
During the year ended December 31, 2009, certain former and existing CNX Gas employees became eligible to participate in the CONSOL Energy Supplemental Retirement Plan. The additional benefit liabilities for these employees have been reflected as Plan Amendments in the reconciliation of the changes in benefit obligation for the year ended December 31, 2009.
Effective January 1, 2007, employees hired by CNX Gas, an 83.3% owned subsidiary, will not be eligible to participate in CNX Gas’ non-contributory defined benefit retirement plan. In lieu of participation in the non-contributory defined benefit retirement plan, these employees began receiving an additional 3% company contribution into their defined contribution plan.
Certain subsidiaries of CONSOL Energy provide medical and life insurance benefits to retired employees not covered by the Coal Industry Retiree Health Benefit Act of 1992. The medical plans contain certain cost sharing and containment features, such as deductibles, coinsurance, health care networks and coordination with Medicare. Prior to August 1, 2003, substantially all employees became eligible for these benefits if they had ten years of company service and attained age 55. Effective August 1, 2003, the base eligibility was changed to age 55 with 20 years of service for salaried employees. In addition, effective January 1, 2004, a medical plan cost sharing arrangement with all salaried employees and retirees was adopted. These participants will now contribute a target of 20% of the medical plan operating costs. Contributions may be higher, dependent on either years of service or a combination of age and years of service at retirement. Prospective annual cost increases of up to 6% will be shared by CONSOL Energy and the participants. Annual cost increases in excess of 6% will be the sole responsibility of the participants. Also, any salaried or non-represented hourly employees that were hired or rehired effective January 1, 2007, or later, will not become eligible for retiree health benefits. In lieu of traditional retiree health coverage, if certain eligibility requirements are met, these employees may be eligible to receive a retiree medical spending allowance of two thousand two hundred and fifty dollars for each year of service at retirement. Newly employed inexperienced employees represented by the United Mine Workers of America, hired after January 1, 2007, will not be eligible to receive retiree benefits. In lieu of these benefits, these employees will receive a defined contribution benefit of $1 per each hour worked.
CONSOL Energy adopted the measurement provisions of the Defined Benefit Plans Topic of the FASB Accounting Standards Codification during the year ended December 31, 2008. As a result of the adoption, the Company recognized an increase of $2,278 and $42,599 in the liabilities for pension and other postretirement benefits, respectively. These increases were accounted for as a reduction in the January 1, 2008 balance of retained earnings.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The reconciliation of changes in the benefit obligation, plan assets and funded status of these plans at December 31, 2009 and 2008, is as follows:
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The components of net periodic benefit costs are as follows:
Amounts included in accumulated other comprehensive income, expected to be recognized in 2010 net periodic benefit costs:
The following table provides information related to pension plans with an accumulated benefit obligation in excess of plan assets:
Assumptions:
The weighted-average assumptions used to determine benefit obligations are as follows:
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The weighted-average assumptions used to determine net periodic benefit costs are as follows:
The long-term rate of return is the sum of the portion of total assets in each asset class held multiplied by the expected return for that class, adjusted for expected expenses to be paid from the assets. The expected return for each class is determined using the plan asset allocation at the measurement date and a distribution of compound average returns over a 20-year time horizon. The model uses asset class returns, variances and correlation assumptions to produce the expected return for each portfolio. The return assumptions used forward-looking gross returns influenced by the current Treasury yield curve. These returns recognize current bond yields, corporate bond spreads and equity risk premiums based on current market conditions.
The assumed health care cost trend rates are as follows:
Assumed health care cost trend rates have a significant effect on the amounts reported for the medical plans. A one-percentage point change in assumed health care cost trend rates would have the following effects:
Assumed discount rates also have a significant effect on the amounts reported for both pension and other benefit costs. A one-quarter percentage point change in assumed discount rate would have the following effect on benefit costs:
Plan Assets:
The company’s overall investment strategy for its pension plan assets is to meet current and future benefit payment needs through diversification across asset classes, fund strategies and fund managers to achieve an optimal balance between risk and return and between income and growth of assets through capital appreciation. The target allocations for plan assets are 36 percent U.S. equity securities, 24 percent non-U.S. equity securities
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
and 40 percent fixed income. Both the equity and fixed income portfolios are comprised of both active and passive investment strategies. The Trust is primarily invested in Mercer Global Investments (MGI) Common Collective Trusts. Equity securities consist of investments in large and mid/small cap companies with non-U.S. equities being derived from both developed and emerging markets. Fixed income securities consist of U.S. as well as international instruments, including emerging markets. The core domestic fixed income portfolios invest in government, corporate, asset-backed securities and mortgage-backed obligations. The average quality of the fixed income portfolio must be rated at least “investment grade” by nationally recognized rating agencies. Within the fixed income asset class, investments are invested primarily across various strategies such that its overall profile strongly correlates with the interest rate sensitivity of the Trust’s liabilities in order to reduce the volatility resulting from the risk of changes in interest rates and the impact of such changes on the Trust’s overall financial status. Derivatives, interest rate swaps, options and futures are permitted investments for the purpose of reducing risk and to extend the duration of the overall fixed income portfolio; however, they may not be used for speculative purposes. All or a portion of the assets may be invested in mutual funds or other comingled vehicles so long as the pooled investment funds have an adequate asset base relative to their asset class; are invested in a diversified manner; and have management and/or oversight by an Investment Advisor registered with the Securities and Exchange Commission. The Retirement Board, as appointed by the CONSOL Energy Board of Directors, reviews the investment program on an ongoing basis including asset performance, current trends and developments in capital markets, changes in Trust liabilities and ongoing appropriateness of the overall investment policy.
The fair values of plan assets at December 31, 2009 by asset category are as follows:
(a) This category includes investments in United States common stocks.
(b) This category invests primarily in common stock of large cap companies in the U.S. with above average earnings growth and revenue expectations. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
risk characteristics. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The strategy is benchmarked to the Russell 1000 Growth Index.
(c) This category invests primarily in U.S. large cap companies that appear to be undervalued relative to their intrinsic value. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The strategy is benchmarked to the Russell 1000 Value Index.
(d) This category invests in small to mid-sized U.S. companies with above average earnings growth and revenue expectations. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The smaller cap orientation of the strategy requires the investment team to be cognizant of liquidity and capital constraints, which are monitored on an ongoing basis. The strategy is benchmarked to the Russell 2500 Growth Index.
(e) This category invests in small to mid-sized U.S. companies that appear to be undervalued relative to their intrinsic value. It targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The smaller cap orientation of the strategy requires the investment team to be cognizant of liquidity and capital constraints, which are monitored on an ongoing basis. The strategy is benchmarked to the Russell 2500 Growth Index.
(f) This category invests primarily in U.S. dollar-denominated investment grade and government securities. It may also invest in opportunistically in out-of-benchmark positions including U.S. high yield, non-U.S. bonds, and Treasury Inflation-Protected Securities (TIPs). The strategy seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics, and total portfolio duration is targeted to be within 20% of the benchmark’s duration. Total exposure to high yield issues is typically less than 10%, inclusive of direct investment in high yield and exposure through other core fixed income funds. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The strategy is benchmarked to the Barclays Capital Aggregate Index.
(g) This category invests in all cap companies operating in developed and emerging markets outside the U.S. The strategy targets broad diversification across economic sectors and seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Total exposure to emerging markets is typically 10-15%, inclusive of direct investment in emerging markets and exposure through other non-U.S. equity funds. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The strategy is benchmarked to the MSCI EAFE Index.
(h) This category invests in a passively managed U.S. long duration investment grade portfolio at a 90% weight and a passively managed U.S. Long Treasury portfolio at a 10% weight. It seeks to provide broad exposure to U.S. long duration investment grade credit while allowing for short term liquidity through a strategic allocation to U.S. Treasuries. The strategy is benchmarked 90% to the Barclays Capital U.S. Long Credit Index and 10% to the Barclays Capital Long Treasury.
(i) This category invests primarily in U.S. dollar denominated investment grade bonds and government securities with durations between 9 and 11 years. It may also invest opportunistically in out-of-benchmark positions including U.S. high yield, non-U.S. bonds, municipal bonds, and TIPs. The strategy seeks to achieve lower overall portfolio volatility by investing in complementary active managers with varying risk characteristics. Fund selection and allocations within the portfolio are implemented by MGI’s investment management team. The strategy is benchmarked to the Barclays Capital U.S. Long Government/Credit Index.
(j) This category invests in common stock of U.S. large cap companies. The strategy is benchmarked to the S&P 500 Index.
(k) This category invests primarily in U.S. dollar-denominated investment grade bonds and government securities. The strategy and its underlying passive investments are benchmarked to the Barclays Capital Aggregate Index.
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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
(l) This category invests primarily in U.S. dollar-denominated investment grade bonds and government securities with durations between 9 and 11 years. The strategy and its underlying passive investments are benchmarked to the Barclays Capital Long Government/Credit Index.
(m) This category seeks to reduce the volatility of the plan’s funded status and extend the duration of the assets by investing in a series of ultra long duration portfolios with target durations of up to 35 years. Each underlying portfolio is managed by a sub-advisor and consists of five interest rate swaps with sequential target or maturity dates, with the longest dated portfolio maturing in 2045. The interest rate swaps are fully collateralized, resulting in no leverage. The cash collateral is invested by the sub-advisor in an actively managed cash strategy that seeks to provide a return in excess of 3 month LIBOR. The ultra long duration strategy is used in conjunction with liability driven investing solutions, which seek to align the duration of the assets to the plan’s liabilities. The Strategy is benchmarked to a Custom Liability Benchmark Portfolio.
There are no direct investments in CONSOL Energy stock held by these plans at December 31, 2009 or 2008.
There are no assets in the other postretirement benefit plans at December 31, 2009 or 2008.
Cash Flows:
CONSOL Energy expects to contribute to the pension trust using prudent funding methods. Currently, depending on asset values and asset returns held in the trust, we expect to contribute $63,600 to our pension plan trust in 2010. Pension benefit payments are primarily funded from the trust. CONSOL Energy does not expect to contribute to the other postemployment plan in 2010. We intend to pay benefit claims as they are due.
The following benefit payments, reflecting expected future service, are expected to be paid:
Note 16-Coal Workers’ Pneumoconiosis (CWP) and Workers’ Compensation:
CONSOL Energy is responsible under the Federal Coal Mine Health and Safety Act of 1969, as amended, for medical and disability benefits to employees and their dependents resulting from occurrences of coal workers’ pneumoconiosis disease. CONSOL Energy is also responsible under various state statutes for pneumoconiosis benefits. CONSOL Energy primarily provides for these claims through a self-insurance program. The calculation of the actuarial present value of the estimated pneumoconiosis obligation is based on an annual actuarial study by independent actuaries. The calculation is based on assumptions regarding disability incidence, medical costs, indemnity levels, mortality, death benefits, dependents and interest rates. These assumptions are derived from actual company experience and outside sources. Actuarial gains associated with CWP have resulted from numerous legislative changes over many years which have resulted in lower approval rates for filed claims than our assumptions originally reflected. Actuarial gains have also resulted from lower incident rates and lower severity of claims filed than our assumption originally reflected.
CONSOL Energy is also responsible to compensate individuals who sustain employment related physical injuries or some types of occupational diseases and, on some occasions, for costs of their rehabilitation. Workers’
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
compensation laws will also compensate survivors of workers who suffer employment related deaths. Workers’ compensation laws are administered by state agencies with each state having its own set of rules and regulations regarding compensation that is owed to an employee that is injured in the course of employment. CONSOL Energy primarily provides for these claims through a self-insurance program. CONSOL Energy recognizes an actuarial present value of the estimated workers’ compensation obligation calculated by independent actuaries. The calculation is based on claims filed and an estimate of claims incurred but not yet reported as well as various assumptions. The assumptions include discount rate, future health care trend rate, benefit duration and recurrence of injuries. Actuarial gains associated with workers’ compensation have resulted from discount rate changes, several years of favorable claims experience, various favorable state legislation changes and overall lower incident rates than our assumptions.
CONSOL Energy adopted the measurement provisions of the Defined Benefit Plans Topic of the FASB Accounting Standards Codification during the year ended December 31, 2008. As a result of this adoption, the Company recognized an increase of $4,871 and $11,523 in liabilities for coal workers’ pneumoconiosis and workers’ compensation, respectively. These increases were accounted for as a reduction in the January 1, 2008 balance of retained earnings.
(a) Amounts offset by a contractual receivable included in Other Assets on the Consolidated Balance Sheets.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The components of the net periodic cost (credit) are as follows:
Amounts included in accumulated other comprehensive income, expected to be recognized in 2010 net periodic benefit costs:
Assumptions:
The weighted-average discount rate used to determine benefit obligations and net periodic (benefit) cost are as follows:
Assumed discount rates have a significant effect on the amounts reported for both CWP benefits and Workers’ Compensation costs. A one-quarter percentage point change in assumed discount rate would have the following effect on benefit costs:
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Cash Flows:
CONSOL Energy does not intend to make contributions to the CWP or Workers’ Compensation plans in 2010. We intend to pay benefit claims as they become due.
The following benefit payments, which reflect expected future claims as appropriate, are expected to be paid:
Note 17-Other Employee Benefit Plans:
UMWA Pension and Benefit Trusts:
Certain subsidiaries of CONSOL Energy also participate in a defined benefit multi-employer pension plan negotiated with the United Mine Workers of America (the UMWA) and contained in the National Bituminous Coal Wage Agreement (the NBCWA). The NBCWA currently calls for contribution amounts to be paid into the multi-employer 1974 Pension Trust based principally on hours worked by UMWA-represented employees. The current contribution rates called for by the NBCWA are: $4.25 per hour worked in 2009, $5.00 per hour worked in 2010 and $5.50 per hour worked in 2011. Total contributions for a year may differ from total expenses for the year due to the timing of actual contributions compared to the date of assessment. Total contributions to the UMWA 1974 Pension Trust were $25,620, $21,140 and $11,354 for the years ended December 31, 2009, 2008 and 2007, respectively. These multi-employer pension plan contributions are expensed as incurred. The Pension Protection Act requires a minimum funding ratio of 80% be maintained for this multi-employer pension plan and if the plan is determined to have a funded ratio of less than 80% it will be deemed to be “endangered” or "seriously endangered", and if less than 65%, it will be deemed to be in “critical” status, and will in either case be subject to additional funding requirements. Under the Pension Act, the multi-employer plan's actuary must certify the plan's funded status for each plan year. Based on an estimated funded percentage of 91.4%, a certification was provided by the multi-employer plan actuary, stating that the 1974 Pension Trust was in neither “endangered” nor “critical” status for the plan year beginning July 1, 2008. However, the volatile economic environment and the recent rapid deterioration in the equity markets caused investment income and the value of investment assets held in the 1974 Pension Trust to decline and lose value.
In late 2008, the Worker, Retiree and Employer Recovery Act of 2008 (“WRERA”) was enacted. Under WRERA, a plan is permitted temporarily to avoid applying the Pension Act's requirements for improving its financial status by giving a plan the option to elect to retain its prior year zone status and to freeze the plan's zone status at the level determined for 2008. WRERA also required that the plan's actuary certify the plan's actual zone status for 2009. On September 28, 2009, based on an estimated funded percentage of 74%, the 1974 Pension Trust's actuary provided the Pension Act zone certification for 2009, certifying that the 1974 Pension Trust is “seriously endangered” for the plan year beginning July 1, 2009. Thereafter, pursuant to WRERA, the 1974 Pension Trust elected to retain its 2008 funded status of neither “endangered” nor “critical” for the plan year
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
beginning July 1, 2009. If the freeze election had not been made, the 1974 Pension Trust's zone status for 2009 as certified by its actuary would have been “seriously endangered” and the 1974 Pension Trust would have been required to develop a funding improvement plan.
The freeze election only applies for the 2009 plan year. If the 1974 Pension Trust is certified to be endangered, seriously endangered or in critical status for the plan year beginning July 1, 2010, steps will have to be taken under the Pension Act to improve its funded status. Such a determination would require certain subsidiaries of CONSOL Energy to make additional contributions pursuant to a funding improvement plan implemented in accordance with the Pension Act and, therefore, could have a material impact on our operating results.
The Coal Industry Retiree Health Benefit Act of 1992 (the Act) created two multi-employer benefit plans: (1) the United Mine Workers of America Combined Benefit Fund (the Combined Fund) into which the former UMWA Benefit Trusts were merged, and (2) the 1992 Benefit Fund. CONSOL Energy subsidiaries account for required contributions to these multi-employer trusts as expense when incurred.
The Combined Fund provides medical and death benefits for all beneficiaries of the former UMWA Benefit Trusts who were actually receiving benefits as of July 20, 1992. The 1992 Benefit Fund provides medical and death benefits to orphan UMWA-represented members eligible for retirement on February 1, 1993, and who actually retired between July 20, 1992 and September 30, 1994. The Act provides for the assignment of beneficiaries to former employers and the allocation of unassigned beneficiaries (referred to as orphans) to companies using a formula set forth in the Act. The Act requires that responsibility for funding the benefits to be paid to beneficiaries be assigned to their former signatory employers or related companies. This cost is recognized when contributions are assessed. Total contributions under the Act were $22,646, $24,343 and $32,916 for the years ended December 31, 2009, 2008 and 2007, respectively. Costs were reduced in 2007 by $30,389 due to the March 2007 settlement agreement with the Combined Fund that resolved all previous issues relating to the calculation of payments to the Combined Fund. See Note 24-Commitments and Contingencies in Notes to Audited Financial Statements for additional details on the settlement agreement. Based on available information at December 31, 2009, CONSOL Energy’s obligation for the Act is estimated at approximately $182,084.
The UMWA 1993 Benefit Plan is a defined contribution plan that was created as the result of negotiations for the NBCWA of 1993. This plan provides health care benefits to orphan UMWA retirees who are not eligible to participate in the Combined Fund, the 1992 Benefit Fund, or whose last employer signed the 1993 or a later NBCWA and who subsequently goes out of business. Contributions to the trust under the 2007 agreement are $1.44 per hour worked by UMWA represented employees for the year ended December 31, 2009, comprised of a $0.50 per hour worked under the labor agreement and $0.94 per hour worked by UMWA represented employees under the Tax Relief and Health Care Act of 2006 (the 2006 Act). Contributions to the trust under the 2007 agreement are $1.77 per hour worked by UMWA represented employees for the year ended December 31, 2008, comprised of a $0.50 per hour worked under the labor agreement and $1.27 per hour worked by UMWA represented employees under the 2006 Act. The contribution rate for the year ended December 31, 2007, was $2.00 per hour worked by UMWA represented employees, comprised of $0.50 per hour worked under the labor agreement and $1.50 per hour worked under the 2006 Act. Total contributions were $9,072, $11,494 and $11,627 for the years ended December 31, 2009, 2008 and 2007, respectively.
Pursuant to the provisions of the 2006 Act and the 1992 Plan, CONSOL Energy is required to provide security in an amount based on the annual cost of providing health care benefits for all individuals receiving benefits from the 1992 Plan who are attributable to CONSOL Energy, plus all individuals receiving benefits from
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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
an individual employer plan maintained by CONSOL Energy who are entitled to receive such benefits. In accordance with the 2006 Act and the 1992 Plan, the outstanding letters of credit to secure our obligation were $61,734 and $60,695 for years ended December 31, 2009 and 2008, respectively. The 2009 and 2008 security amounts were based on the annual cost of providing health care benefits and included a reduction in the number of eligible employees.
At December 31, 2009, approximately 34.5% of CONSOL Energy’s workforce was represented by the UMWA.
Equity Incentive Plans:
CONSOL Energy has an equity incentive plan that provides grants of stock-based awards to key employees and to non-employee directors. See Note 18 for a further discussion of CONSOL Energy’s stock-based compensation.
The CNX Gas equity incentive plan consists of the following components: stock options, stock appreciation rights, restricted stock units, performance awards, performance share units, cash awards and other stock-based awards. The total number of shares of CNX Gas common stock with respect to which awards may be granted under CNX Gas’ plan is 2,500,000. CNX Gas stock-based compensation expense, excluding allocated portions from CONSOL Energy resulted in pre-tax expense of $6,311, $3,379 and $3,260 to CONSOL Energy for the years ended December 31, 2009, 2008 and 2007, respectively.
Long Term Incentive Compensation:
CNX Gas had a long-term incentive program. This program allowed for the award of performance share units (PSUs). A PSU represents a contingent right to receive a cash payment, determined by reference to the value of one share of the Company’s common stock. The total number of units earned, if any, by a participant was based on the Company’s total stock holder return relative to the stock holder return of a pre-determined peer group of companies. CNX Gas recognized compensation costs over the requisite service period. The basis of the compensation costs was re-valued quarterly. Approximately $8,779 and $2,231 of compensation costs have been recognized for the years ended December 31, 2008 and 2007, respectively. A credit to expense of approximately $1,434 was recognized for the year ended December 31, 2009 as a result of the decline in the value of the expected payout prior to the exchange transaction discussed below.
During the second quarter of 2009, CNX Gas recognized the effect of an exchange offer that allowed participants in the CNX Gas Long-Term Incentive Program to exchange their unvested performance share units for CONSOL Energy restricted stock units. The excess fair value of the replacement restricted stock units over the original performance stock units resulted in $2,738 of incremental restricted stock compensation expense being immediately recognized. Additionally, a liability of $10,347 for the cash settlement of the CNX Gas performance share units was reclassified into equity due to the issuance of RSUs. As a result of the completed exchange offer there are no outstanding performance share units at December 31, 2009.
Investment Plan:
CONSOL Energy has an investment plan available to all domestic, non-represented employees. Effective January 1, 2006, the company match was 6% of base pay for all non-represented employees except for those employees of Fairmont Supply Company whose match remains at 50% of the first 12% of base pay. In addition,
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(Dollars in thousands, except per share data)
effective January 1, 2007, the definition of eligible compensation for employee deferrals and company match was amended to include overtime for all non-represented employees except for those employees of Fairmont Supply Company whose definition of eligible compensation will remain unchanged. CNX Gas employees hired on or after January 1, 2007 also receive an additional 3% non-elective contribution in lieu of participation in the CNX Gas pension plan. Total payments and costs were $24,353, $23,091 and $17,896 for the years ended December 31, 2009, 2008 and 2007, respectively.
Long-Term Disability:
CONSOL Energy has a Long-Term Disability Plan available to all full-time salaried employees. The benefits for this plan are based on a percentage of monthly earnings, offset by all other income benefits available to the disabled.
Long-Term Disability related liabilities are included in Deferred Credits and Other Liabilities-Other and Other Accrued Liabilities and amounted to $30,097 and $29,645 for the years ended December 31, 2009 and 2008, respectively.
Note 18-Stock-Based Compensation:
CONSOL Energy adopted the CONSOL Energy Inc. Equity Incentive Plan on April 7, 1999. The plan provides for grants of stock-based awards to key employees and to non-employee directors. Amendments to the plan have been approved by the Board of Directors since the commencement of the plan. In 2009, the Board of Directors approved an increase in the total number of shares by 5,600,000 bringing the total number of shares of common stock that can be covered by grants at December 31, 2009 to 23,800,000 of which 2,600,000 are available for issuance of awards other than stock options. The Plan, as amended, will provide that the aggregate number of shares available for issuance under the Plan will be reduced by one share for each share issued in settlement of Performance Share Units (PSUs) or Restricted Stock Units (RSUs) and by 1.44 for any other award. No award of stock options may be exercised under the plan after the tenth anniversary of the effective date of the award.
In accordance with the Stock Compensation Topic of the FASB Accounting Standards Codification, CONSOL Energy recognizes stock-based compensation costs net of an estimated forfeiture rate and recognizes the compensation costs for only those shares expected to vest on a straight-line basis over the requisite service period of the award, which is generally the option vesting term, or to an employee’s eligible retirement date, if earlier and applicable. The total stock-based compensation expense recognized was $32,723, $21,807 and $20,983 for the years ended December 31, 2009, 2008 and 2007, respectively. The related deferred tax benefit totaled $12,490, $8,293 and $7,938, for the years ended December 31, 2009, 2008 and 2007, respectively.
CONSOL Energy examined its historical pattern of option exercises in an effort to determine if there were any discernable activity patterns based on certain employee populations. From this analysis, CONSOL Energy identified two distinct employee populations. CONSOL Energy used the Black-Scholes option pricing model to value the options for each of the employee populations. The table below presents the weighted average expected term in years of the two employee populations. The expected term computation is based upon historical exercise
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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
patterns and post-vesting termination behavior of the populations. The risk-free interest rate was determined for each vesting tranche of an award based upon the calculated yield on U.S. Treasury obligations for the expected term of the award. The expected forfeiture rate is based upon historical forfeiture activity. A combination of historical and implied volatility is used to determine expected volatility and future stock price trends. Total fair value of options granted during the years ended December 31, 2009, 2008 and 2007 were $9,950, $11,395 and $9,912, respectively. The fair value of share-based payment awards was estimated using the Black-Scholes option pricing model with the following assumptions and weighted average fair values:
A summary of the status of stock options granted is presented below:
These stock options will terminate ten years after the date on which they were granted. The employee stock options, covered by the Equity Incentive Plan adopted April 7, 1999, vest 25% per year, beginning one year after the grant date for awards granted prior to 2007. Employee stock options awarded after December 31, 2006 vest 33% per year, beginning one year after the grant date. There are 4,848,213 stock options outstanding under the Equity Incentive plan. Additionally, there are 446,180 fully vested employee stock options outstanding which had vesting terms ranging from six months to one year. Non-employee director stock options vest 33% per year, beginning one year after the grant date. There are 92,747 stock options outstanding under these grants. The vesting of all options will accelerate in the event of death, disability or retirement and may accelerate upon a change in control of CONSOL Energy. In 2008, the compensation committee of the board of directors changed the retirement eligible acceleration of vesting to require a minimum vesting period of twelve months. This change is effective for all stock based compensation awards issued after January 1, 2008.
The aggregate intrinsic value in the table above represents the total pretax intrinsic value (the difference between CONSOL Energy’s closing stock price on the last trading day of the year ended December 31, 2009, and
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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
the option’s exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on December 31, 2009. This amount varies based on the fair market value of CONSOL Energy’s stock. Total intrinsic value of options exercised for the year ended December 31, 2009, 2008 and 2007 was $4,502, $55,131 and $65,294, respectively.
Cash received from option exercises for the years ended December 31, 2009, 2008 and 2007 was $2,547, $15,215 and $19,224, respectively. The excess tax benefit realized for the tax deduction from option exercises totaled $3,270, $22,003 and $23,682 for the years ended December 31, 2009, 2008 and 2007, respectively. This excess tax benefit is included in cash flows from financing activities in the Consolidated Statements of Cash Flows.
Under the Equity Incentive Plan, CONSOL Energy granted certain employees and non-employee directors restricted stock unit awards. These awards entitle the holder to receive shares of common stock as the award vests. Compensation expense will be recognized over the vesting period of the units. The total fair value of the restricted stock units granted during the years ended December 31, 2009, 2008 and 2007 were $42,720, $5,950 and $6,373, respectively. The total fair value of shares vested during the years ended December 31, 2009, 2008 and 2007 was $18,092, $4,720 and $3,641, respectively. The following represents the unvested restricted stock units and corresponding fair value (based upon the closing share price) at the date of grant:
Under the Equity Incentive Plan, CONSOL Energy granted certain employees performance share unit awards. These awards entitle the holder to receive shares of common stock subject to the achievement of certain market and performance goals. Compensation expense will be recognized over the performance measurement period of the units in accordance with the provisions of the Stock Compensation Topic of the FASB Accounting Standards Codification for awards with market and performance vesting conditions. At December 31, 2009, achievement of the market and performance goals is believed to be probable. The total fair value of performance share units granted during the years ended December 31, 2009, 2008 and 2007 were $5,684, $4,904 and $3,237. The following represents the unvested performance share unit awards and their corresponding fair value (based upon the closing share price) at the date of grant:
As of December 31, 2009, $24,570 of total unrecognized compensation cost related to unvested awards is expected to be recognized over a weighted-average period of 1.57 years. When employee stock options are exercised and restricted and performance share unit awards become vested, the issuances are made from CONSOL Energy’s treasury stock shares which have been acquired as part of CONSOL Energy’s share repurchase program as previously discussed in Note 1.
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(Dollars in thousands, except per share data)
Note 19-Accumulated Other Comprehensive Loss:
Components of accumulated other comprehensive loss consists of the following:
The cash flow hedges that CONSOL Energy holds are disclosed in Note 23. The adjustments for Actuarially Determined Liabilities are disclosed in Note 15 and Note 16.
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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Note 20-Supplemental Cash Flow Information:
Note 21-Concentration of Credit Risk and Major Customers:
CONSOL Energy markets steam coal, principally to electric utilities in the United States, Canada and Western Europe, metallurgical coal to steel and coke producers worldwide, and natural gas primarily to gas wholesalers. As of December 31, 2009 and 2008, accounts receivable from utilities were $215,743 and $222,808, respectively. As of December 31, 2009 and 2008, accounts receivable from steel and coke producers were $43,448 and $40,788, respectively. As of December 31, 2009 and 2008, accounts receivable from gas wholesalers were $43,421 and $61,764, respectively. Credit is extended based on an evaluation of the customer’s financial condition, and generally collateral is not required. Credit losses have been consistently minimal.
For the years ended December 31, 2009, 2008 and 2007, no customer comprised over 10% of our revenues.
Note 22-Fair Values of Financial Instruments:
Effective January 1, 2008, CONSOL Energy adopted the provision for Fair Value of Financial Assets and Financial Liabilities as required by the Financial Accounting Standards Board Accounting Standards Codification. As a result of the adoption, CONSOL Energy elected not to measure any additional financial assets or liabilities at fair value, other than those which were previously recorded at fair value prior to the adoption.
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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The financial instruments measured at fair value on a recurring basis are summarized below:
The following methods and assumptions were used to estimate the fair values of financial instruments, which the fair value option was not elected:
Cash and cash equivalents: The carrying amount reported in the balance sheets for cash and cash equivalents approximates its fair value due to the short maturity of these instruments.
Short-term notes payable: The carrying amount reported in the balance sheets for short-term notes payable approximates its fair value due to the short-term maturity of these instruments.
Long-term debt: The fair values of long-term debt are estimated using discounted cash flow analyses, based on current market rates for instruments with similar cash flows.
The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows:
Note 23-Derivative Instruments:
CONSOL Energy enters into financial derivative instruments to manage our exposure to commodity price volatility. Our derivatives are accounted for under the Derivatives and Hedging Topic of the Financial Accounting Standards Board Accounting Standards Codification. We measure each derivative instrument at fair value and record it on the balance sheet as either an asset or liability. Changes in the fair value of the derivatives are recorded currently in earnings unless special hedge accounting criteria are met. For derivatives designated as fair value hedges, the changes in fair value of both the derivative instrument and the hedged item are recorded in earnings. For derivatives designated as cash flow hedges, the effective portions of changes in fair value of the derivative are reported in Other Comprehensive Income or Loss (OCI) and reclassified into earnings in the same period or periods which the forecasted transaction affects earnings. The ineffective portions of hedges are recognized in earnings in the current year. CONSOL Energy currently utilizes only cash flow hedges that are considered highly effective.
CONSOL Energy formally assesses both at inception of the hedge and on an ongoing basis, whether each derivative is highly effective in offsetting changes in the fair values or the cash flows of the hedged item. If it is determined that a derivative is not highly effective as a hedge or if a derivative ceases to be a highly effective hedge, CONSOL Energy will discontinue hedge accounting prospectively.
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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
CONSOL Energy is exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is subject to continuing review. All of the counterparties to CONSOL Energy’s natural gas derivative instruments also participate in CONSOL Energy’s revolving credit facility. The Company has not experienced any issues of non-performance by derivative counterparties.
CONSOL Energy has entered into forward and option contracts on various commodities to manage the price risk associated with the forecasted revenues from those commodities. The objective of these hedges is to reduce the variability of the cash flows associated with the forecasted revenues from the underlying commodities.
As of December 31, 2009, the total notional amount of the Company’s outstanding natural gas forward contracts was 85.1 billion cubic feet. These forward contracts are forecasted to settle through December 31, 2012 and meet the criteria for cash flow hedge accounting. During the next year, $60,307 of unrealized gain is expected to be reclassified from Other Comprehensive Income and into earnings. No gains or losses have been reclassified into earnings as a result of the discontinuance of cash flow hedges.
As of December 31, 2009, CONSOL Energy did not have any outstanding coal sales options. For the years ended December 31, 2009 and 2008, CONSOL Energy recognized, in Other Income on the Consolidated Statement of Income, a gain of $2,368 and a loss of ($335), respectively, for the coal sales options which were not designated as hedging instruments.
The fair value of CONSOL Energy’s derivative instruments at December 31, 2009 is as follows:
The effect of derivative instruments on the Consolidated Statement of Income for the year ended December 31, 2009 is as follows:
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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The fair value of CONSOL Energy’s derivative instruments at December 31, 2008 is as follows:
The effect of derivative instruments on the consolidated statement of income for the year ended December 31, 2008 is as follows:
Note 24-Commitments and Contingent Liabilities:
CONSOL Energy and its subsidiaries are subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations including environmental remediation, employment and contract disputes and other claims and actions arising out of the normal course of business. Our current estimates related to these pending claims, individually and in the aggregate, are immaterial to the financial position, results of operations or cash flows of CONSOL Energy. However, it is reasonably possible that the ultimate liabilities in the future with respect to these lawsuits and claims may be material to the financial position, results of operations or cash flows of CONSOL Energy.
In 2008, the Pennsylvania Department of Conservation and Natural Resources (Commonwealth) filed a six-count Complaint in the Court of Common Pleas of Allegheny County, Pennsylvania, claiming that the Company’s underground longwall mining activities caused cracks and seepage damage to the Ryerson Park Dam, thereby eliminating the Ryerson Park Lake. The Commonwealth claimed that the Company is liable for dam reconstruction costs, lake restoration costs and natural resources damages totaling $58,000. The Court stayed the proceedings in the state court, holding that the Commonwealth should pursue administrative agency review of the claim. Furthermore, the Court found that the Commonwealth could not recover natural resources damages under applicable law. The issue of whether the dam was damaged by subsidence is being reviewed by the
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NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Department of Environmental Protection (DEP). If the DEP determines that there is causation, a second phase will be set to determine the remedy. As to the underlying claim, the Company believes it is not responsible for the damage to the dam and that numerous grounds exist upon which to attack the propriety of the claims. The Company intends to vigorously defend the case. However, it is reasonably possible that the ultimate liability in the future with respect to these claims may be material to the financial position, results of operations, or cash flows of CONSOL Energy.
One of our subsidiaries, Fairmont Supply Company (Fairmont), which distributes industrial supplies, currently is named as a defendant in approximately 22,500 asbestos claims in state courts in Pennsylvania, Ohio, West Virginia, Maryland, Mississippi, New Jersey and Illinois. Because a very small percentage of products manufactured by third parties and supplied by Fairmont in the past may have contained asbestos and many of the pending claims are part of mass complaints filed by hundreds of plaintiffs against a hundred or more defendants, it has been difficult for Fairmont to determine how many of the cases actually involve valid claims or plaintiffs who were actually exposed to asbestos-containing products supplied by Fairmont. In addition, while Fairmont may be entitled to indemnity or contribution in certain jurisdictions from manufacturers of identified products, the availability of such indemnity or contribution is unclear at this time, and in recent years, some of the manufacturers named as defendants in these actions have sought protection from these claims under bankruptcy laws. Fairmont has no insurance coverage with respect to these asbestos cases. Past payments by Fairmont with respect to asbestos cases have not been material. Our current estimates related to these asbestos claims, individually and in the aggregate, are immaterial to the financial position, results of operations and cash flows of CONSOL Energy. However, it is reasonably possible that payments in the future with respect to pending or future asbestos cases may be material to the financial position, results of operations or cash flows of CONSOL Energy.
CONSOL Energy was notified in November 2004 by the United States Environmental Protection Agency (EPA) that it is a potentially responsible party (PRP) under Superfund legislation with respect to the Ward Transformer site in Wake County, North Carolina. At that time, the EPA also identified 38 other PRPs for the Ward Transformer site. The EPA, CONSOL Energy and two other PRPs entered into an administrative Settlement Agreement and Order of Consent, requiring those PRPs to undertake and complete a PCB soil removal action, at and in the vicinity of the Ward Transformer property. Another party joined the participating PRPs and reduced CONSOL Energy’s interim allocation share from 46% to 32%. In June 2008, while conducting the PCB soil excavation on the Ward property, it was determined that PCBs have migrated onto adjacent properties.
The current estimated cost of remedial action for the area CONSOL Energy was originally named a PRP, including payment of the EPA’s past and future cost, is approximately $55,000. The current estimated cost of the most likely remediation plan for one of the additional areas discovered is approximately $10,000, although the removal action plan is not yet approved by the EPA. Also, in September 2008, the EPA notified CONSOL Energy and 60 other PRPs that there were additional areas of potential contamination allegedly related to the Ward Transformer Site. Current estimates of the cost or potential range of cost for this area are not yet available. There was $3,422, $7,080 and $1,780 of expense recognized in Cost of Goods Sold and Other Charges for the years ended December 31, 2009, 2008 and 2007, respectively. CONSOL Energy funded $5,500, $6,000 and $1,256 in the years ended December 31, 2009, 2008 and 2007, respectively, to an independent trust established for this remediation. The remaining liability at December 31, 2009 of $5,914 is reflected in Other Accrued Liabilities at December 31, 2009.
As of April 30, 2009, CONSOL Energy and the other participating PRPs had asserted CERCLA cost recovery and contribution claims against approximately 225 nonparticipating PRPs to recover a share of the costs
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(Dollars in thousands, except per share data)
incurred and to be incurred to conduct the removal actions at the Ward Site. CONSOL Energy’s portion of probable recoveries from settled claims is estimated to be $3,620. Accordingly, an asset has been included in Other Assets for these claims. We cannot predict the ultimate outcome of this Superfund site; however, it is reasonably possible that payments in the future with respect to this lawsuit may be material to the financial position, results of operations or cash flows of CONSOL Energy.
As part of conducting mining activities at the Buchanan Mine, our subsidiary, Consolidation Coal Company (“CCC”), has to remove water from the mine. Several actions have arisen with respect to the removal of naturally accumulating and pumped water from the Buchanan Mine:
Yukon Pocahontas Coal Company, Buchanan Coal Company and Sayers-Pocahontas Coal Company filed an action on March 22, 2004 against CCC which is presently pending in the Circuit Court of Buchanan County, Virginia (the “Yukon Action”). The action is related to CCC’s depositing of untreated water from its Buchanan Mine into the void spaces of nearby mines of one of our other subsidiaries, Island Creek Coal Company (“ICCC”). The plaintiffs are seeking to stop CCC from depositing any additional water in these areas, to require CCC to remove the water that is stored there along with any remaining impurities, to recover over $3,252,000 for alleged damages to the coal and gas estates and punitive damages in the amount of $350. Plaintiffs have also asserted damage claims of $150,000 against CONSOL Energy, CNX Gas Company, LLC and ICCC. The Yukon group has recently filed a demand for arbitration (the “2008 Arbitration”) against ICCC which makes similar claims relating to breach of the lease for water deposits and lost coal claims.
CCC obtained a revision to its environmental permit to deposit water from its Buchanan Mine into void spaces of VP3, and to permit the discharge of water into the nearby Levisa River under controlled conditions. Plaintiffs in the Yukon Action along with the Town of Grundy, Virginia, Buchanan County Board of Supervisors, and others have appealed the revision.
We believe that CCC has and continues to have the right to deposit mine water from Buchanan Mine into void spaces at nearby mines. We also believe CCC was properly issued environmental permits to deposit water from the Buchanan Mine into VP3 and to discharge water into the Levisa River. CCC and the other named CONSOL Energy defendants in the Yukon Action deny all liability and intend to vigorously defend the action filed against them in connection with the removal and deposit of water from the Buchanan Mine, as well as environmental permits issued to CCC. Consequently, we have not recognized any liability related to these actions. However, if a temporary or permanent injunction were to be issued against CCC, if the environmental permits were temporarily suspended or revoked, or if damages were awarded to plaintiffs, the result may be material to the financial position, results of operations or cash flows of CONSOL Energy.
In 2006, CONSOL Energy and CCC were served with a summons in the name of the Commonwealth of Virginia with the Circuit Court of Buchanan County, Virginia regarding a special grand jury presentment in response to citizens’ complaints that noise resulting from the ventilation fan at the Buchanan Mine constitutes a public nuisance. CONSOL Energy and CCC deny that the operation of the ventilation fan is a public nuisance and intend to vigorously defend this proceeding. However, if the operation of the ventilation fan is ordered to be stopped, the result may be material to the financial position, results of operations or cash flows of CONSOL Energy.
In, 2007 Bluestone Coal Corporation filed a lawsuit against the Company and its subsidiary, CNX Land Resources, in the United States District Court for the Southern District of West Virginia. The suit alleges that the Company breached a contract that allegedly provides Bluestone with an option to lease coal reserves within a seven-and-one-half mile radius of Bishop, WV and seeks damages of $1,200,000. The writing relied upon only
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(Dollars in thousands, except per share data)
refers to a right of first refusal, rather than an option. The lawsuit has been settled. The terms of the settlement are confidential, but include CONSOL Energy granting to Bluestone the option to acquire certain mining assets and reserves. The settlement did not materially impact the financial position, results of operations or cash flows of CONSOL Energy.
South Carolina Electric & Gas Company (“SCE&G”), a utility, has demanded arbitration, seeking $36,000 in damages against CONSOL of Kentucky and CONSOL Energy Sales Company. SCE&G claims it suffered damages in obtaining cover coal to replace coal which was not delivered in 2008 under a coal sales agreement. The Company counterclaimed against SCE&G for $9,400 for terminating coal shipments under the sales agreement which SCE&G had agreed could be made up in 2009. A hearing on the claims is scheduled for October 11, 2010. The named CONSOL Energy defendants deny all liability and intend to vigorously defend the action filed against them. However, if damages were awarded to SCE&G, the result may be material to the financial position, results of operations or cash flows of CONSOL Energy.
In 2009, a fish kill occurred in Dunkard Creek, which is a creek with segments in both Pennsylvania and West Virginia. The fish kill was caused by the growth of golden brown algae in the creek, which appears to be an invasive species. Our subsidiary, CCC, discharges treated mine water into Dunkard Creek from its Blacksville No. 2 Mine and from its Loveridge Mine. The discharges have levels of chlorides that cause Dunkard Creek to exceed West Virginia in-stream water quality standards. Prior to the fish kill, CCC was subject to an Agreed Order with the West Virginia Department of Environmental Protection that sets forth a schedule for compliance with these in-stream chloride limits. On December 18, 2009, the West Virginia Department of Environmental Protection issued a unilateral Order that imposes additional conditions on CCC's discharges into Dunkard Creek and requires CCC to develop a plan for long-term treatment of those and other high-chloride discharges. The Dunkard Creek fish kill is being investigated by several agencies, including the West Virginia Department of Environmental Protection, the West Virginia Department of Natural Resources, the Pennsylvania Department of Environmental Protection, and the Pennsylvania Fish and Boat Commission. The U.S. Environmental Protection Agency is also involved. We are cooperating with these investigations. We do not believe that there is a connection between the fish kill and our discharge of water into Dunkard Creek, but the investigation of the matter is continuing. If such a causal connection were established or if we are required to comply with in-stream chloride limits on an accelerated basis, it is reasonably possible that the liabilities or costs that could be incurred by CONSOL Energy in the future with respect to these matters may be material to the financial position, results of operations, or cash flows of CONSOL Energy.
In 2007, GeoMet, Inc. and certain of its affiliates filed a lawsuit against CONSOL Energy and certain of its affiliates, including CNX Gas Company LLC, in the Circuit Court for the County of Tazewell, Virginia. The lawsuit alleges, among other things, that the defendants have violated the Virginia Antitrust Act in their dealings with GeoMet in southwest Virginia. The complaint, as amended, seeks injunctive relief, compensatory damages of $385,600 and treble damages. CNX Gas continues to believe this lawsuit to be without merit and intends to vigorously defend it. We cannot predict the ultimate outcome of this litigation; however, it is reasonably possible that the ultimate liabilities in the future with respect to these lawsuits and claims may be material to the financial position, results of operations, or cash flows of CNX Gas.
In 2009, CNX Gas received a civil investigative demand for information and documents from the Attorney General of the Commonwealth of Virginia regarding the company's exploration, production, transportation and sale of coalbed methane gas in Virginia. According to the request, the Attorney General is investigating whether the company may have violated the Virginia Antitrust Act. The request for information does not constitute the commencement of legal proceedings and does not make any specific allegations against the company. CNX Gas
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(Dollars in thousands, except per share data)
does not believe that it has violated the Virginia Antitrust Act and CNX Gas is cooperating with the Attorney General's investigation.
The Company is a party to a case filed in 2007 captioned Earl Kennedy (and others) v. CNX Gas and CONSOL Energy in the Court of Common Pleas of Greene County, Pennsylvania. The lawsuit alleges that CNX Gas and CONSOL Energy trespassed and converted gas and other minerals allegedly belonging to the plaintiffs in connection with wells drilled by CNX Gas. The complaint, as amended, seeks injunctive relief, including having CNX Gas be removed from the property, and compensatory damages of $20,000. The suit also sought to overturn existing law as to the ownership of coalbed methane in Pennsylvania, but that claim was dismissed by the court; the plaintiffs are seeking to appeal that dismissal. CNX Gas believes this lawsuit to be without merit and intends to vigorously defend it. We cannot predict the ultimate outcome of this litigation; however, it is reasonably possible that the ultimate liabilities in the future with respect to these lawsuits and claims may be material to the financial position, results of operations, or cash flows of CNX Gas.
In 2005, Buchanan County, Virginia (through its Board of Supervisors and Commissioner of Revenue) filed a lawsuit against CNX Gas Company LLC in the Circuit Court of the County of Buchanan for the year 2002; the county has since filed and served three substantially similar cases for years 2003, 2004 and 2005. These cases have been consolidated. The complaint alleges that CNX Gas’ calculation of the license tax on the basis of the wellhead value (sales price less post production costs) rather than the sales price is improper. For the period from 1999 through mid 2002, CNX Gas paid the tax on the basis of the sales price, but we have filed a claim for a refund for these years. Since 2002, we have continued to pay Buchanan County taxes based on our method of calculating the taxes. This litigation has been settled on terms that do not materially impact the financial position or the results of operations of CNX Gas or CONSOL Energy.
In 2007, the assigned operators, including subsidiaries of CONSOL Energy, and the Combined Fund entered into a settlement agreement that resolved all issues relating to the calculation and imposition of higher per beneficiary premium rates. The settlement agreement provides for full reimbursement of the higher per beneficiary premium rate. The settlement agreement provided for full reimbursement of higher per beneficiary premium rate previously paid by CONSOL Energy subsidiaries and related interest. In the year ended December 31, 2007, CONSOL Energy received $30,389 which was reflected as a reduction to cost of goods sold and other charges.
In 2007, production at the Buchanan Mine was suspended after several roof falls damaged some of the ventilation controls inside the mine. Production resumed in March 2008. The incident was covered under our property and business interruption insurance policy, subject to certain deductibles. Business interruption recoveries of $50,000 were recognized as Other Income in the year ended December 31, 2008, $42,000 in the coal segment and $8,000 in the gas segment.
In 2008, the Emergency Economic Stabilization Act of 2008 (the EESA Act) was signed into law. The EESA Act contained a section that authorizes certain coal producers and exporters who had filed a Black Lung Excise Tax (BLET) return on or after October 1, 1990, to request a refund of the BLET paid on export sales during these years. The EESA Act requires that the U.S. Treasury refund a coal producer or exporter an amount equal to the BLET erroneously paid on export sales in prior years along with interest computed at the statutory rates applicable to overpayments. In the year ended December 31, 2008, CONSOL Energy recognized a receivable related to these refunds of $58,983, including interest of $32,444. In relation to this receivable, CONSOL Energy recognized a payable of $3,187 that was owed to third parties upon collection of the refunds. The receivable was collected and the related payables were paid in the year ended December 31, 2009.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
At December 31, 2009, CONSOL Energy has provided the following financial guarantees, unconditional purchase obligations and letters of credit to certain third parties, as described by major category in the following table. These amounts represent the maximum potential total of future payments that we could be required to make under these instruments. These amounts have not been reduced for potential recoveries under recourse or collateralization provisions. Generally, recoveries under reclamation bonds would be limited to the extent of the work performed at the time of the default. No amounts related to these financial guarantees and letters of credits are recorded as liabilities on the financial statements. CONSOL Energy management believes that these guarantees will expire without being funded, and therefore the commitments will not have a material adverse effect on financial condition.
CONSOL Energy and CNX Gas enter into long-term unconditional purchase obligations to procure major equipment purchases, natural gas firm transportation, gas drilling services and other operating goods and services. These purchase obligations are not recorded on the Consolidated Balance Sheets. As of December 31, 2009, the purchase obligations for each of the next five years were as follows:
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Costs related to major equipment purchases under these purchase obligations was $89,261, $10,957 and $15,886 for the years ended December 31, 2009, 2008 and 2007. Firm transportation expense under these purchase obligations was $21,668, $11,476 and $9,390 for the years ended December 31, 2009, 2008 and 2007 respectively. Expenses related to gas drilling purchase obligations were $585 for the year ended December 31, 2009. Expenses related to other operating goods and services under these purchase obligations was $120 and $60 for the years ended December 31, 2009 and 2008.
Employee-related financial guarantees have primarily been provided to support the United Mine Workers’ of America’s 1992 Benefit Plan and various state workers’ compensation self-insurance programs. Environmental financial guarantees have primarily been provided to support various performance bonds related to reclamation and other environmental issues. Gas financial guarantees have primarily been provided to support various performance bonds related to land usage and restorative issues. Other guarantees have been extended to support insurance policies, legal matters and various other items necessary in the normal course of business. Other guarantees have also been provided to promise the full and timely payments to lessors of mining equipment and support various other items necessary in the normal course of business.
Note 25-Segment Information:
CONSOL Energy has two principal business units: Coal and Gas. The principal activities of the Coal unit are mining, preparation and marketing of steam coal, sold primarily to power generators, and metallurgical coal, sold to metal and coke producers. The Coal unit includes four reportable segments. These reportable segments are Northern Appalachian, Central Appalachian, Metallurgical and Other Coal. Each of these reportable segments includes a number of operating segments (mines). For the year ended December 31, 2009, the Northern Appalachian aggregated segment includes the following mines: Blacksville #2, Robinson Run, McElroy, Loveridge, Bailey, Enlow Fork, Mine 84 and Shoemaker. For the year ended December 31, 2009, the Central Appalachian aggregated segment includes the following mines: Jones Fork Complex, the Miller Creek Complex, the Fola Complex and the Terry Eagle Complex. For the year ended December 31, 2009, the Metallurgical aggregated segment includes the following mines: Buchanan and Amonate Complex. The Other Coal segment includes our purchased coal activities, idled mine cost, coal segment business units not meeting aggregation criteria, as well as various other activities assigned to the coal segment but not allocated to each individual mine. The principal activity of the Gas unit is to produce pipeline quality methane gas for sale primarily to gas wholesalers. CONSOL Energy’s All Other segment includes terminal services, river and dock services, industrial supply services and other business activities, including rentals of buildings and flight operations. Intersegment sales have been recorded at amounts approximating market. Operating profit for each segment is based on sales less identifiable operating and non-operating expenses. Certain reclassifications of 2008 and 2007 segment information have been made to conform to the 2009 presentation.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Industry segment results for the year ended December 31, 2009 are:
(A) There were no sales to customers aggregating over 10% of total revenue in 2009.
(B) Includes equity in earnings of unconsolidated affiliates of $5,663, $637 and $9,408 for Coal, Gas and All Other, respectively.
(C) Includes investments in unconsolidated equity affiliates of $12,569, $24,590 and $46,374 for Coal, Gas and All Other, respectively.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Industry segment results for the year ended December 31, 2008 are:
(D) There were no sales to customers aggregating over 10% of total revenue in 2008.
(E) Includes equity in earnings of unconsolidated affiliates of $2,534, $551 and $8,055 for Coal, Gas and All Other, respectively.
(F) Includes investments in unconsolidated equity affiliates of $9,386, $25,204 and $38,406 for Coal, Gas and All Other, respectively. Also, included in the Coal segment is $58,983 of receivables related to the Emergency Economic Stabilization Act of 2008.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Industry segment results for the year ended December 31, 2007 are:
(G) There were no sales to customers aggregating over 10% in 2007.
(H) Includes equity in earnings of unconsolidated affiliates of $1,027, $2,174 and $3,350 for Coal, Gas and All Other, respectively.
(I) Includes investments in unconsolidated equity affiliates of $3,101, $56,865 and $34,900 for Coal, Gas and All Other, respectively.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Reconciliation of Segment Information to Consolidated Amounts:
Revenue and Other Income:
(J) Excludes amounts specifically related to the gas segment.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Enterprise-Wide Disclosures:
CONSOL Energy’s Revenues by geographical location:
(K) CONSOL Energy attributes revenue to individual countries based on the location of the customer.
CONSOL Energy’s Property, Plant and Equipment by geographical location are:
Note 26-Guarantor Subsidiaries Financial Information:
The payment obligations under the $250,000, 7.875 percent per annum notes due March 1, 2012 issued by CONSOL Energy are jointly and severally, and also fully and unconditionally guaranteed by several subsidiaries of CONSOL Energy. In accordance with positions established by the Securities and Exchange Commission (“SEC”), the following financial information sets forth separate financial information with respect to the parent, CNX Gas, an 83.3% owned guarantor subsidiary, the remaining guarantor subsidiaries and the non-guarantor subsidiaries. CNX Gas is presented in a separate column in accordance with SEC Regulation S-X Rule 3-10. CNX Gas Corporation is a reporting company under Section 12(b) of the Securities Exchange Act of 1933, and as such, CNX Gas Corporation files its own financial statements with the Securities and Exchange Commission and those financial statements, when filed, are publicly available on Edgar. The principal elimination entries include investments in subsidiaries and certain intercompany balances and transactions. CONSOL Energy, the parent, and a guarantor subsidiary manage several assets and liabilities of all other 100% owned subsidiaries. These include, for example, deferred tax assets, cash and other post-employment liabilities. These assets and liabilities are reflected as parent company or guarantor company amounts for purposes of this presentation.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Income Statement for the Year Ended December 31, 2009:
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Balance Sheet for December 31, 2009:
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Condensed Statement of Cash Flows
For the Year Ended December 31, 2009:
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Income Statement for the Year Ended December 31, 2008:
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Balance Sheet for December 31, 2008:
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Condensed Statement of Cash Flows
For the Year Ended December 31, 2008:
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Income Statement for the Year Ended December 31, 2007:
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Condensed Statement of Cash Flows
For the Year Ended December 31, 2007:
Supplemental Coal Data (unaudited):
* Proved and probable coal reserves are the equivalent of “demonstrated reserves” under the coal resource classification system of the U.S. Geological Survey. Generally, these reserves would be commercially mineable at year-end prices and cost levels, using current technology and mining practices.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
CONSOL Energy’s coal reserves are located in nearly every major coal-producing region in North America. At December 31, 2009, 898 million tons were assigned to mines either in production, temporarily idle, or under development. The proved and probable reserves at December 31, 2009 include 3,960 million tons of steam coal reserves, of which approximately 8 percent has a sulfur content equivalent to less than 1.2 pounds sulfur dioxide per million British thermal unit (Btu), and an additional 14 percent has a sulfur content equivalent to between 1.2 and 2.5 pounds sulfur dioxide per million Btu. The reserves also include 560 million tons of metallurgical coal in consolidated reserves, of which approximately 62 percent has a sulfur content equivalent to less than 1.2 pounds sulfur dioxide per million Btu, and an additional 37 percent has a sulfur content equivalent to between 1.2 and 2.5 pounds sulfur dioxide per million Btu. A significant portion of this metallurgical coal can also serve the steam coal market.
Other Supplemental Information-Supplemental Gas Data (unaudited)
The following information was prepared in accordance with the Financial Accounting Standards Board’s Accounting Standards Update No. 2010-03, “Extractive Activities-Oil and Gas (Topic 932).”
Capitalized Costs:
Costs incurred for property acquisition, exploration and development (*):
(*) Includes costs incurred whether capitalized or expensed.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Results of Operations for Producing Activities:
The following is production, average sales price and average production costs, excluding ad valorem and severance taxes, per unit of production:
During the years ended December 31, 2009, 2008 and 2007, we drilled 247, 534 and 370 net development wells, respectively. Of these wells drilled in the year ended December 31, 2009 there was one dry well. There were no dry wells in the years ended December 31, 2008 and 2007.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
During the years ended December 31, 2009, 2008 and 2007, we drilled 18, 56 and 9 net exploratory wells, respectively. Of the wells drilled in the years ended December 31, 2009 and 2008, there were one and three dry wells, respectively. There were no dry wells in the year ended December 31, 2007.
At December 31, 2009, there were six development wells in the process of being drilled. Drilling activities are currently in progress to complete the drilling of these wells by the end of March 2010.
At December 31, 2009, there were ten exploratory wells in the process of being drilled. Drilling and evaluation activities will be in process throughout the 2010 period.
CNX Gas is committed to provide 44.1 Bcf of gas under existing contracts or agreements over the course of the next two years. CNX Gas expects to produce sufficient quantities from existing proved developed reserves to satisfy these commitments.
Most of our development wells and proved acreage are located in Central Appalachia. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments are satisfied. The following table sets forth the number of CNX Gas producing wells, developed acreage and undeveloped acreage at December 31, 2009:
(1) Net acres do not include acreage attributable to the working interests of our principal joint venture partners and the portions of certain proved developed acreage attributable to property we have leased to third-party producers. Additional adjustments (either increases or decreases) may be required as we further develop title to and confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Proved Oil and Gas Reserve Quantities:
The preparation of our gas reserve estimates are completed in accordance with CNX Gas’ prescribed internal control procedures, which include verification of input data into a gas reserve forecasting and economic evaluation software, as well as multi-functional management review. The technical employee responsible for overseeing the preparation of the reserve estimates is a petroleum engineer. Our 2009 gas reserve results were audited by Netherland, Sewell and Associates, Inc. The technical person primarily responsible for overseeing the audit of our reserves is a certified petroleum engineer. The gas reserve estimates are as follows:
(a) Proved developed and proved undeveloped gas reserves are defined by the Securities and Exchange Commission (SEC) Rule 4.10(a) of Regulation S-X. Generally, these reserves would be commercially recovered under current economic conditions, operating methods and government regulations. CNX Gas cautions that there are many inherent uncertainties in estimating proved reserve quantities, projecting future production rates and timing of development expenditures. Proved oil and gas reserves are estimated quantities of natural gas and coalbed methane gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those reserves expected to be recovered through existing wells, with existing equipment and operating methods.
(b) Revisions are primarily due to efficiencies in operations which resulted in a reduction of operating costs, a comprehensive look into reservoir characterization and well performance.
(c) Extensions and discoveries are due to the addition of our Marcellus Shale acreage and approvals from the Oil & Gas Board in Virginia to drill and complete wells on tighter spacing. Extensions and discoveries also include 120,933 MMcfe as a result of initially applying the amendments of ASC 932 in ASU 2010-03 related to capturing proved undeveloped locations more than one location away if reliable technology can be demonstrated.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
(a) During 2009, various exploration and development drilling and evaluations were completed. Approximately, $45,326 of capital was spent in the year ended December 31, 2009 related to undeveloped reserves that were transferred to developed.
(b) Included in proved undeveloped reserves at December 31, 2009 are approximately 120,000 MMcfe of reserves that have been reported for more than five years that relate specifically to CONSOL Energy’s Buchanan Mine. These undeveloped reserves will be developed in order to de-gas the mine ahead of longwall mining.
The following table represents the capitalized exploratory well cost activity as indicated:
(a) Costs held in exploratory for more than one year represent exploration wells away from existing infrastructure. The additional planned exploration expenditures will allow us to invest in infrastructure to support these fields.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
CNX Gas’ proved gas reserves are located in the United States.
Standardized Measure of Discounted Future Net Cash Flows:
The following information has been prepared in accordance with the provisions of the Financial Accounting Standards Board’s Accounting Standards Update No. 2010-03, “Extractive Activities-Oil and Gas (Topic 932).” This topic requires the standardized measure of discounted future net cash flows to be based on the average, first-day-of-the-month price for the year ended December 31, 2009. Because prices used in the calculation are average prices for that year, the standardized measure could vary significantly from year to year based on the market conditions that occurred.
The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to CNX Gas. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary. CNX Gas’ investment and operating decisions are not based on the information presented, but on a wide range of reserve estimates that include probable as well as proved reserves and on a different price and cost assumptions.
The standardized measure is intended to provide a better means for comparing the value of CNX Gas’ proved reserves at a given time with those of other gas producing companies than is provided by a comparison of raw proved reserve quantities.
(a) The estimated effect on the PV-10 calculation of initially applying the amendments of ASC 932 in ASU 2010-03 was $39,059.
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
The following are the principal sources of change in the standardized measure of discounted future net cash flows during:
CONSOL ENERGY INC. AND SUBSIDIARIES
NOTES TO AUDITED CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in thousands, except per share data)
Supplemental Quarterly Information (unaudited):
(Dollars in thousands)
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures.
Changes in Accountants.
On February 19, 2008 (Dismissal Date) CONSOL Energy dismissed PricewaterhouseCoopers LLP (PwC) as the Company’s independent registered public accounting firm. The Audit Committee of the Board of Directors of the Company recommended and approved the dismissal of PwC.
The reports of PwC on the consolidated financial statements of the Company for the year ended December 31, 2007 did not contain an adverse opinion or a disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope, or accounting principles.
During the year ended December 31, 2007 through the Dismissal Date, there were no disagreements with PwC on any matter of accounting principles or practices, financial statement disclosures, or auditing scope or procedure, which disagreement(s), if not resolved to the satisfaction of PwC, would have caused it to make reference thereto in its reports on the financial statements of the Company for such year. During the year ended December 31, 2007, and through the Dismissal Date, there were no “reportable events” as defined under Item 304(a)(1)(v) of Regulation S-K.
Also, on February 19, 2008, the Audit Committee recommended and approved the selection of Ernst & Young LLP (“Ernst & Young), effective immediately, as the Company’s new independent registered public accounting firm.
During the year ended December 31, 2007, and through the Dismissal Date, neither the Company, nor anyone on its behalf, consulted Ernst & Young regarding either (i) the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered with respect to the financial statements of the Company, and no written report was provided to the Company or oral advice was provided that Ernst & Young concluded was an important factor considered by the Company in reaching a decision as to the accounting, auditing or financial reporting issue; or (ii) any matter that was the subject of a disagreement (as defined in Item 304(a)(1)(iv) of Regulation S-K and the related instructions) or a “reportable event” (as described in Item 304(a)(1)(v) of Regulation S-K).
Disagreements with Accountants on Accounting and Financial Disclosures.
None.
Item 9a.
Item 9a. Controls and Procedures.
Disclosure controls and procedures. CONSOL Energy, under the supervision and with the participation of its management, including CONSOL Energy’s principal executive officer and principal financial officer, evaluated the effectiveness of its “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Securities Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this annual report on Form 10-K. Based on that evaluation, CONSOL Energy’s principal executive officer and principal financial officer have concluded that its disclosure controls and procedures are effective to ensure that information required to be disclosed by CONSOL Energy in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and include controls and procedures designed to ensure that information required to be disclosed by CONSOL Energy in such reports is accumulated and communicated to CONSOL Energy’s management, including CONSOL Energy’s principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.
Management’s Annual Report on Internal Control Over Financial Reporting.
CONSOL Energy’s management is responsible for establishing and maintaining adequate internal control over financial reporting. CONSOL Energy’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.
CONSOL Energy’s internal control over financial reporting includes policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; (2) provide reasonable assurances that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of management and the directors of CONSOL Energy; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of CONSOL Energy’s assets that could have a material effect on our 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.
Management assessed the effectiveness of CONSOL Energy’s internal control over financial reporting as of December 31, 2009. In making this assessment, management 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, management has concluded that CONSOL Energy maintained effective internal control over financial reporting as of December 31, 2009.
The effectiveness of CONSOL Energy’s internal control over financial reporting as of December 31, 2009 has been audited by Ernst and Young, an independent registered public accounting firm, as stated in their report set forth in the Report of Independent Registered Public Accounting Firm in Part II, Item 9a of this annual report on Form 10-K.
Changes in internal controls over financial reporting.
There were no changes that occurred during the fourth quarter of the fiscal year covered by this Annual Report on Form 10-K that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of CONSOL Energy Inc.
We have audited CONSOL Energy Inc.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). CONSOL Energy Inc.’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 appearing under Item 9a. 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, CONSOL Energy Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, 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 sheet of CONSOL Energy Inc. (and Subsidiaries) as of December 31, 2009 and 2008, and the related consolidated statements of income, stockholders’ equity, and cash flows for the years then ended and our report dated February 9, 2010 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Pittsburgh, PA
February 9, 2010
Item 9b.
Item 9b. Other Information.
None.
PART III
Item 10.
Item 10. Directors and Executive Officers and Corporate Governance.
The information required by this Item is incorporated herein by reference from the information under the captions “PROPOSAL NO. 1-ELECTION OF DIRECTORS-Biography of Directors,” “BOARD OF DIRECTORS AND COMPENSATION INFORMATION-BOARD OF DIRECTORS AND ITS COMMITTEES-Corporate Governance Web Page Available Documents,” “BOARD OF DIRECTORS AND COMPENSATION INFORMATION-BOARD OF DIRECTORS AND ITS COMMITTEES-Audit Committee” and “SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE” in the Proxy Statement for the annual meeting of shareholders to be held on May 4, 2010 (the “Proxy Statement”).
Executive Officers of CONSOL Energy
The following is a list of CONSOL Energy executive officers, their ages as of February 15, 2010 and their positions and offices held with CONSOL Energy.
Name
Age
Position
J. Brett Harvey
President and Chief Executive Officer
Nicholas J. DeIuliis
Executive Vice President and Chief Operating Officer
William J. Lyons
Executive Vice President and Chief Financial Officer
P. Jerome Richey
Executive Vice President Corporate Affairs and Chief Legal Officer
Robert P. King
Executive Vice President Business Advancements and Support Services
Robert F. Pusateri
Executive Vice President Energy Sales and Transportation Services
J. Brett Harvey has been President and Chief Executive Officer and a Director of CONSOL Energy since January 1998. He has been a Director of CNX Gas Corporation since June 30, 2005 and he became Chairman of the Board and Chief Executive Officer of CNX Gas Corporation on January 16, 2009. Mr. Harvey is a Director of Barrick Gold Corporation, the world’s largest gold producer, and Allegheny Technologies Incorporated, a specialty metals producer.
Nicholas J. DeIuliis was Senior Vice President-Strategic Planning of CONSOL Energy from November 2004 until August 2005. Prior to that time, Mr. DeIuliis served as Vice President Strategic Planning from April 2002 until November 2004, Director-Corporate Strategy from October 2001 until April 2002, Manager-Strategic Planning from January 2001 until October 2001 and Supervisor-Process Engineering from April 1999 until January 2001. He resigned from his position with CONSOL Energy as of August 8, 2005. He was a Director and President and Chief Executive Officer of CNX Gas Corporation from June 30, 2005 to January 16, 2009, when he became President and Chief Operating Officer of CNX Gas Corporation and Executive Vice President and Chief Operating Officer of CONSOL Energy.
William J. Lyons has been Chief Financial Officer of CONSOL Energy since February 2001 and Chief Financial Officer of CNX Gas Corporation since April 28, 2008. He added the title of Executive Vice President of CONSOL Energy on May 2, 2005 and of CNX Gas Corporation on January 16, 2009. From January 1995 until February 2001, Mr. Lyons held the position of Vice President-Controller for CONSOL Energy. Mr. Lyons joined CONSOL Energy in 1976. He was a Director of CNX Gas Corporation from October 17, 2005 to January 16, 2009. Mr. Lyons is a director of Calgon Carbon Corporation, a supplier of products and services for purifying water and air.
P. Jerome Richey became Executive Vice President-Corporate Affairs and Chief Legal Officer of CONSOL Energy and CNX Gas Corporation on January 16, 2009. He was General Counsel and Corporate Secretary of CONSOL Energy since March 2005, and on June 20, 2007, he added the title of Senior Vice President. Prior to joining CONSOL Energy, Mr. Richey, for more than five years, was a shareholder in the Pittsburgh office for the law firm of Buchanan Ingersoll & Rooney PC.
Robert P. King became Executive Vice President-Business Advancement and Support Services of CONSOL Energy and CNX Gas Corporation on January 16, 2009. Prior to that, he was Senior Vice President-Administration since February 2, 2007 and he served as Vice President-Land from August 2006 to February 2007. Prior to joining CONSOL Energy, Mr. King was Vice President of Interwest Mining Company (a subsidiary of PacifiCorp). Mr. King joined PacifiCorp in November 1990.
Robert F. Pusateri became Executive Vice President-Energy Sales and Transportation Services of CONSOL Energy and CNX Gas Corporation on January 16, 2009. Prior to that, he was named Vice President Sales of CONSOL Energy in 1996 and held that position until he was elected President of CONSOL Energy Sales Company in August 2005. He first became an officer in May 1996.
CONSOL Energy has a written Code of Business Conduct that applies to CONSOL Energy’s Chief Executive Officer (Principal Executive Officer), Chief Financial Officer (Principal Financial Officer) and others. The Code of Business Conduct is available on CONSOL Energy’s website at www.consolenergy.com. Any amendments to, or waivers from, a provision of our code of employee business conduct and ethics that applies to our principal executive officer, principal financial officer, controller, or persons performing similar functions and that relates to any element of the code of ethics enumerated in paragraph (b) of Item 406 of Regulation S-K shall be disclosed by posting such information on our website.
By certification dated May 27, 2009, CONSOL Energy’s Chief Executive Officer certified to the New York Stock Exchange (NYSE) that he was not aware of any violation by the Company of the NYSE corporate governance listing standards. In addition, the required Sarbanes-Oxley Act, Section 302 certifications regarding the quality of our public disclosures were filed by CONSOL Energy as exhibits to this Form 10-K.
Item 11.
Item 11. Executive Compensation.
The information required by this Item is incorporated by reference from the information under the captions “BOARD OF DIRECTORS AND COMPENSATION INFORMATION-DIRECTOR COMPENSATION TABLE-2009,” “BOARD OF DIRECTORS AND COMPENSATION INFORMATION-BOARD OF DIRECTORS AND ITS COMMITTEES-Compensation Committee Interlocks and Insider Participation,” “EXECUTIVE COMPENSATION AND STOCK OPTION INFORMATION” in the Proxy Statement.
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 from the information under the caption “BENEFICIAL OWNERSHIP OF SECURITIES” and “SECURITIES AUTHORIZED FOR ISSUANCE UNDER CONSOL ENERGY EQUITY COMPENSATION PLAN” in the Proxy Statement.
Item 13.
Item 13. Certain Relationships and Related Transactions and Director Independence.
The information requested by this Item is incorporated by reference from the information under the caption “Proposal No. 1-Election of Directors-Related Party Policy and Procedures” and “Determination of Director Independence” in the Proxy Statement.
Item 14.
Item 14. Principal Accounting Fees and Services.
The information required by this Item is incorporated by reference from the information under the captions “ACCOUNTANTS AND AUDIT COMMITTEE-INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM,” including subsections entitled “Audit Fees,” “Audit-Related Fees,” “Tax Fees,” “All Other Fees” and “Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services” in the Proxy Statement.
Item 15.
Item 15. Exhibit Index
Supplemental Information
No annual report or proxy material has been sent to shareholders of CONSOL Energy at the time of filing of this Form 10-K. An annual report will be sent to shareholders subsequent to the filing of this Form 10-K. Said annual report will be forwarded to the commission when the same are sent to shareholders of CONSOL Energy.
In accordance with SEC Release 33-8238, Exhibits 32.1 and 32.2 are being furnished and not filed.
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, as of the 9th day of February, 2010.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed as of the 9th day of February, 2010, by the following persons on behalf of the registrant in the capacities indicated:
SCHEDULE II
CONSOL ENERGY INC. AND SUBSIDIARIES
Valuation and Qualifying Accounts
(Dollars in thousands)